1 ================================================================================ SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 --------------------- FORM 10-K --------------------- /X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1995 / / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 COMMISSION FILE NUMBER: 1-9743 ENRON OIL & GAS COMPANY (Exact name of registrant as specified in its charter) DELAWARE 47-0684736 (State or other jurisdiction (I.R.S. Employer of incorporation or organization) Identification No.) 1400 SMITH STREET, HOUSTON, TEXAS 77002-7369 (Address of principal executive offices) (zip code) REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 713-853-6161 --------------------- SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT: <TABLE> <CAPTION> NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED ------------------- ----------------------- <S> <C> Common Stock, $.01 par value New York Stock Exchange </TABLE> SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: NONE Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes /X/ No / /. Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. /X/. Aggregate market value of the voting stock held by nonaffiliates of the registrant, based on the closing sale price in the daily composite list for transactions on the New York Stock Exchange on March 1, 1996 was $1,535,085,875. As of March 1, 1996, there were 159,976,840 shares of the registrant's Common Stock, $.01 par value, outstanding. DOCUMENTS INCORPORATED BY REFERENCE. Certain portions of the registrant's definitive Proxy Statement for the May 7, 1996 Annual Meeting of Shareholders ("Proxy Statement") are incorporated in Part III by reference. ================================================================================
2 TABLE OF CONTENTS PART I <TABLE> <CAPTION> PAGE ---- <S> <C> <C> <C> Item 1. Business General................................................................... 1 Business Segments......................................................... 2 Exploration and Production................................................ 2 Marketing................................................................. 5 Wellhead Volumes and Prices, and Lease and Well Expenses.................. 7 Other Natural Gas Marketing Volumes and Prices............................ 8 Competition............................................................... 8 Regulation................................................................ 8 Relationship Between the Company and Enron Corp. ......................... 11 Other Matters............................................................. 13 Current Executive Officers of the Registrant.............................. 15 Item 2. Properties.................................................................. 16 Oil and Gas Exploration and Production Properties and Reserves............ 16 Item 3. Legal Proceedings........................................................... 19 Item 4. Submission of Matters to a Vote of Security Holders......................... 19 PART II Item 5. Market for the Registrant's Common Equity and Related Shareholder Matters... 20 Item 6. Selected Financial Data..................................................... 21 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations................................................................ 22 Item 8. Financial Statements and Supplementary Data................................. 30 Item 9. Disagreements on Accounting and Financial Disclosure........................ 30 PART III Item 10. Directors and Executive Officers of the Registrant.......................... 30 Item 11. Executive Compensation...................................................... 30 Item 12. Security Ownership of Certain Beneficial Owners and Management.............. 30 Item 13. Certain Relationships and Related Transactions.............................. 30 PART IV Item 14. Exhibits, Financial Statement Schedule, and Reports on Form 8-K............. 30 </TABLE> i
3 PART I ITEM 1. BUSINESS GENERAL Enron Oil & Gas Company (the "Company"), a Delaware corporation organized in 1985, is engaged, either directly or through a marketing subsidiary with regard to domestic operations or through various subsidiaries with regard to international operations, in the exploration for, and the development, production and marketing of, natural gas and crude oil primarily in major producing basins in the United States, as well as in Canada, Trinidad and India and, to a lesser extent, selected other international areas. The Company's principal producing areas are further described under "Exploration and Production" below. At December 31, 1995, the Company's estimated net proved natural gas reserves were 3,343 billion cubic feet ("Bcf"), including 1,180 Bcf of proved undeveloped methane reserves in the Big Piney deep Paleozoic formations and amounts related to a volumetric production payment and estimated net proved crude oil, condensate and natural gas liquids reserves were 50 million barrels ("MMBbl"). (See "Supplemental Information to Consolidated Financial Statements"). At such date, approximately 78% of the Company's reserves (on a natural gas equivalent basis) was located in the United States, 10% in Canada, 8% in Trinidad and 4% in India. As of December 31, 1995, the Company employed approximately 740 persons. The Company's business strategy is to maximize the rate of return on investment of capital by controlling both operating and capital costs and enhancing the certainty of future revenues through the use of various marketing mechanisms. This strategy enhances the generation of both income and cash flow from each unit of production and allows for the growth of production on a cost-effective basis by optimizing the reinvestment of cash flow. The Company refocused its 1995 drilling activity away from natural gas deliverability and toward natural gas reserve enhancement and crude oil exploitation in the United States in response to the decline in United States natural gas prices in recent periods. The Company is also focusing on the cost-effective utilization of advances in technology associated with gathering, processing and interpretation of 3-D seismic data, developing reservoir simulation models and drilling operations through the use of new and/or improved drill bits, mud motors, mud additives, formation logging techniques and reservoir fracturing methods. These advanced technologies are used, as appropriate, throughout the Company to reduce the risks associated with all aspects of oil and gas reserve exploration, exploitation and development. The Company implements its strategy by emphasizing the drilling of internally generated prospects in order to find and develop low cost reserves. Achieving and maintaining the lowest possible cost structure are also important goals in the implementation of the Company's strategy. Consistent with the Company's desire to optimize the use of its assets, it also maintains a strategy of selling select oil and gas properties that for various reasons may no longer fit into future operating plans, or which are not assessed to have sufficient future growth potential and when the economic value to be obtained by selling the properties and reserves in the ground is evaluated to be greater than what would be obtained by holding the properties and producing the reserves over time. As a result, the Company typically receives each year a varying but substantial level of proceeds related to such sales which proceeds are available for general corporate use. The closing on December 13, 1995 of the sale by Enron Corp. of approximately 31 million outstanding shares of the common stock of the Company reduced Enron Corp.'s ownership in the Company from 80% to 61%. (See "Relationship Between the Company and Enron Corp."). Unless the context otherwise requires, all references herein to the Company include Enron Oil & Gas Company, its predecessors and subsidiaries, and any reference to the ownership of interest or pursuit of operations in any international areas by the Company recognizes that all such interests are owned and operations are pursued by subsidiaries of Enron Oil & Gas Company. Unless the context otherwise requires, all references herein to Enron Corp. include Enron Corp., its predecessors and affiliates, other than the Company and its predecessors and subsidiaries. With respect to information on the Company's working interest in wells or acreage, "net" oil and gas wells or acreage are determined by multiplying "gross" oil and gas wells or acreage by the Company's working interest in the wells or acreage. Unless otherwise defined, all references to wells are gross. 1
4 BUSINESS SEGMENTS The Company's operations are all natural gas and crude oil exploration and production related. Accordingly, such operations are classified as one business segment. EXPLORATION AND PRODUCTION NORTH AMERICAN OPERATIONS The Company's seven principal United States producing areas are the Big Piney area, South Texas area, East Texas area, Offshore Gulf of Mexico area, Canyon Trend area, Pitchfork Ranch area and Vernal area. Properties in these areas comprised approximately 67% of the Company's United States reserves (on a natural gas equivalent basis) and 90% of the Company's maximum United States net natural gas deliverability as of December 31, 1995 and are substantially all operated by the Company. The Company's other United States natural gas and crude oil producing properties are located primarily in other areas of Texas, Utah, New Mexico, Oklahoma, California and Kansas. At December 31, 1995, 95% of the Company's proved United States reserves, including the reserves in the Big Piney deep Paleozoic formations, (on a natural gas equivalent basis) was natural gas and 5% was crude oil, condensate and natural gas liquids. A substantial portion of the Company's United States natural gas reserves is in long-lived fields with well-established production histories. The Company believes that opportunities exist to increase production in many of these fields through continued infill and other development drilling. The Company also has natural gas and crude oil producing properties located in Western Canada, primarily in the provinces of Alberta, Saskatchewan and Manitoba. Big Piney Area. The Company's largest reserve accumulation is located in the Big Piney area in Sublette and Lincoln counties in southwestern Wyoming. The Company is the holder of the largest productive acreage base in this area, with approximately 245,000 net acres under lease directly within field limits. The Company operates approximately 535 natural gas wells in this area in which it owns an 87% average working interest. Deliveries from the area net to the Company averaged 90 million cubic feet ("MMcf") per day of natural gas and 2.0 thousand barrels ("MBbl") per day of crude oil, condensate, and natural gas liquids in 1995. At December 31, 1995, natural gas deliverability net to the Company was approximately 140 MMcf per day. The current principal producing intervals are the Frontier and Mesaverde formations. The Frontier formation, which occurs at 6,500 to 10,000 feet, contains approximately 54% of the Company's Big Piney proved developed reserves. The Company drilled 26 wells in the Big Piney area in 1995. Although natural gas drilling has been curtailed in this area during 1995 in response to market conditions, numerous drilling opportunities will be available for several years. In 1995, the Company recorded as proved undeveloped reserves 1,180 Bcf of methane contained, along with high concentrations of carbon dioxide as well as small amounts of other gaseous substances, in the deep Wyoming Paleozoic formation located under acreage leased by the Company and held by production in the Big Piney area. The Company is actively pursuing the consummation of a market or markets from several different potential sources to facilitate realizing the value of these reserves. South Texas Area. The Company's activities in South Texas are focused in the Lobo, Wilcox and Frio producing horizons. The principal areas of activity are in the Lobo and Wilcox Trends which occur primarily in Webb, Zapata and Starr counties. The Company operates approximately 320 wells in the South Texas area. Production is primarily from the Upper Wilcox and Lobo sands at depths ranging from 5,000 to 13,000 feet. The Company has approximately 197,000 net acres under lease in this area. Natural gas deliveries net to the Company averaged approximately 158 MMcf per day in 1995. At December 31, 1995, natural gas deliverability from this area net to the Company was approximately 155 MMcf per day which was impacted during 1995 by the sale of selected properties. The Company drilled 45 wells in the South Texas area in 1995 and participated in a 2
5 sizable 3-D seismic acquisition effort. An active drilling program in this area is anticipated to continue for several years. East Texas Area. The Company's activities in the East Texas area are primarily in the Carthage field, located in Panola County, and the North Milton field, located in northern Harris County. The Carthage field is the Company's newest area of concentration. This field is one of the most prolific fields in East Texas with production primarily from the Cotton Valley, Travis Peak and Pettit formations. In 1995, properties were acquired that doubled the Company's acreage position to 17,000 acres. The Company drilled 36 wells in the East Texas area in 1995 and anticipates an active drilling program will continue for several years. The Company has an average 71% working interest in its holdings. The Company has continued its activity in the North Milton field where it now operates 19 wells and holds a 100% working interest in the acreage. Further drilling is planned for 1996. At December 31, 1995, deliverability from the East Texas area was approximately 50 MMcf per day of natural gas with almost 1.2 MBbl per day of crude oil, condensate and natural gas liquids both net to the Company. Offshore Gulf of Mexico Area. At December 31, 1995, the Company held an interest in 174 blocks in the Offshore Gulf of Mexico area totaling approximately 485,000 net acres. Of the 174 blocks, 119 are operated by the Company. These interests are located predominantly in federal waters offshore Texas and Louisiana. During 1995, the Company acquired a 50% interest in essentially all of the Offshore Gulf of Mexico properties previously owned by Santa Fe Minerals, Inc. complementing the Company's previously owned interests and adding significantly to the Company's offshore operations. Natural gas deliveries from this area averaged 124 MMcf per day during 1995 net to the Company. A substantial portion of such deliveries was from interests in the Matagorda trend with significant volumes also coming from the Mustang Island area. Deliverability from this area at December 31, 1995 was 155 MMcf per day net to the Company sourced principally as noted above. The Company has maintained an active drilling program in this area during 1995 and anticipates a similar program to continue for several years. Canyon Trend Area. The Company's activities in this area have been concentrated in Crockett, Sutton, Terrell and Val Verde Counties, Texas where the Company drilled 384 natural gas wells during the period 1992 through 1995. The Company holds approximately 99,000 net acres and now operates approximately 635 natural gas wells in this area in which it owns a 97% average working interest. Production is from the Canyon sands and Strawn limestone at depths from 5,500 to 12,500 feet. In 1995, natural gas deliveries net to the Company averaged 57 MMcf per day and at December 31, 1995, natural gas deliverability net to the Company was approximately 50 MMcf per day. The Company has maintained an active drilling program in the Canyon Trend area during 1995 and expects a similar program to continue for several years. Pitchfork Ranch Area. The Pitchfork Ranch area located in Lea County, New Mexico, produces primarily from the Bone Spring, Atoka and Morrow formations. In 1995, deliveries net to the Company averaged 28 MMcf per day of natural gas and approximately 2.8 MBbl per day of crude oil, condensate and natural gas liquids. At December 31, 1995, deliverability net to the Company was approximately 25 MMcf per day of natural gas and 2.6 MBbl per day of crude oil, condensate and natural gas liquids. The Company holds approximately 31,000 net acres and recently acquired a 3-D seismic survey over this area. The Company expects to maintain an active drilling program in this area for several years. Vernal Area. In the Vernal area, located primarily in Uintah County, Utah, the Company operates approximately 200 producing wells and presently controls approximately 75,000 net acres. In 1995, natural gas deliveries net to the Company from the Vernal area averaged 19 MMcf per day which represents deliverability. Production is from the Green River and Wasatch formations located at depths between 4,500 and 8,000 feet. The Company has an average working interest of approximately 60%. Although the drilling of natural gas wells was deferred in 1995 in the Vernal area in response to market conditions, numerous drilling opportunities will be available for several years. Canada. The Company is engaged in the exploration for and the development, production and marketing of natural gas and crude oil and the operation of natural gas processing plants in western Canada, principally in the provinces of Alberta, Saskatchewan, and Manitoba. The Company conducts operations from offices in 3
6 Calgary. The Company produces natural gas from seven major areas and crude oil from four major areas. The Sandhills area in Southwestern Saskatchewan is the largest single producing area where 75 wells were drilled in 1995 resulting in deliverability net to the Company from the field of approximately 38 MMcf per day at December 31, 1995. Canadian natural gas deliverability net to the Company at December 31, 1995 was approximately 95 MMcf per day, and the Company held approximately 347,000 net undeveloped acres in Canada. The Company expects to maintain an active drilling program for several years. OUTSIDE NORTH AMERICA OPERATIONS The Company has producing operations offshore Trinidad and India and was recently awarded by the government of Venezuela the rights to pursue exploration, exploitation and development of reserves in the Gulf of Paria East Block offshore the eastern state of Soucre and is conducting exploration in selected other international areas. Properties offshore Trinidad and India comprised 100% of the Company's proved reserves and production outside of North America at year end 1995. Trinidad. In November 1992, the Company was awarded a 95% working interest concession in the South East Coast Consortium ("SECC") Block offshore Trinidad, encompassing three undeveloped fields, previously held by three government-owned energy companies. The Kiskadee field has been developed, the Ibis field is under development and the Oil Bird field is anticipated to be developed over the next three to five years. Existing surplus processing and transportation capacity at the Pelican field facilities owned and operated by Trinidad and Tobago government-owned companies is being used to process and transport the production. Natural gas is being sold into the local market under a take-or-pay agreement with the National Gas Company of Trinidad and Tobago. In 1995, deliveries net to the Company averaged 107 MMcf per day of natural gas and 5.1 MBbl per day of crude oil and condensate. At December 31, 1995, natural gas deliverability net to the Company was approximately 170 MMcf per day and the Company held approximately 71,000 net undeveloped acres in Trinidad. In 1995, the Company was awarded the right to develop the U(a) block adjacent to the SECC Block and is presently negotiating the terms of a production sharing contract with the Government of Trinidad and Tobago. India. In December 1994, the Company signed agreements covering profit sharing, joint operations and product sales and representing a 30% working interest in and was designated operator of the Tapti, Panna and Mukta Blocks located offshore Bombay, India. The Company is designated operator of all three areas. The blocks were previously operated by the Indian national oil company, Oil & Natural Gas Corporation Limited, which retained a 40% working interest. The 363,000 acre Tapti Block contains two major proved gas accumulations delineated by 22 expendable exploration wells that have been plugged. The Company has initiated a development plan for the Tapti Block accumulations. The 106,000 acre Panna Block and the 192,000 acre Mukta Block are partially developed with 30 wells producing from five producing platforms located in the Panna and Mukta fields. The fields were producing approximately 3.3 MBbl per day of crude oil net to the Company as of December 31, 1995; all associated gas was being flared. The Company intends to continue development of the accumulations and to expand processing capacity to allow crude oil production at full deliverability as well as to permit natural gas sales. Venezuela. The Company was awarded exploration, exploitation and development rights for a block offshore the eastern state of Soucre, Venezuela in early 1996. The Company holds an initial 90 percent working interest in the joint venture. Plans include the completion of a 3-D seismic survey over the most prospective portions of the block in 1996 and initiation of drilling in 1997, with production targeted for mid-1998. Total reserves are estimated at 100 to 300 million barrels gross. Other International. The Company continues to evaluate other selected conventional natural gas and crude oil opportunities outside North America. The Company is pursuing other exploitation opportunities in countries where indigenous natural gas and crude oil reserves have been identified, particularly where synergies in natural gas transportation, processing and power cogeneration can be optimized with other Enron Corp. affiliated companies. In early 1995, the Company, an Enron Corp. affiliate and the Qatar General Petroleum Corporation signed a nonbinding letter of intent concerning the possible development of a liquefied 4
7 natural gas project for natural gas to be produced from a block within the North Dome Field. The Company may jointly hold up to a 40% equity interest in the joint venture and the Company would drill and develop to-be-agreed-upon reserves. In addition, the Company signed nonbinding letters of intent in early 1995 with Uzbekneftigaz, the national oil and gas company of Uzbekistan as well as with Gazprom, the Russian natural gas company, to pursue the feasibility of joint venture development and marketing of previously discovered hydrocarbon reserves in Uzbekistan.The Company is also participating in discussions concerning the potential for conventional oil and gas development opportunities in China, Mozambique, Jordan and Algeria. The Company also holds nonoperating working interests in two conventional oil and gas exploration prospects in the U.K. North Sea. The Company continues evaluation and assessment of its international opportunity portfolio in the coalbed methane recovery arena, including projects in South Wales in the U.K., the Lorraine Basin in France, Galilee Basin in Australia and the San Jiao area and Hedong Basin in China. MARKETING Wellhead Marketing. The Company's North America wellhead natural gas production is currently being sold on the spot market and under long-term natural gas contracts at market responsive prices. In many instances, the long-term contract prices closely approximate the prices received for natural gas being sold on the spot market. Wellhead natural gas volumes from Trinidad are sold at prices that are based on a fixed price schedule with annual escalations. Under terms of the production sharing contract, natural gas volumes in India are to be sold to the Gas Authority of India, Ltd. under a take-or-pay contract at a price linked to a basket of world market fuel oil quotations with floor and ceiling limits. Approximately 30% of the Company's wellhead natural gas production is currently being sold to pipeline and marketing subsidiaries of Enron Corp. The Company believes that the terms of its transactions and agreements with Enron Corp. and/or its affiliates are and intends that future such transactions and agreements will be at least as favorable to the Company as could be obtained from third parties. Substantially all of the Company's wellhead crude oil and condensate is sold under various terms and arrangements at market responsive prices. Other Marketing. Enron Oil & Gas Marketing, Inc. ("EOGM"), a wholly-owned subsidiary of the Company, is a marketing company engaging in various marketing activities. Both the Company and EOGM contract to provide, under short and long-term agreements, natural gas to various purchasers and then aggregate the necessary supplies for the sales with purchases from various sources including third-party producers, marketing companies, pipelines or from the Company's own production. In addition, EOGM has purchased and constructed several small gathering systems in order to facilitate its entry into the gathering business on a limited basis. Both the Company and EOGM utilize other short and long-term hedging and trading mechanisms including sales and purchases utilizing NYMEX-related commodity market transactions. These marketing activities have provided an effective balance in managing a portion of the Company's exposure to commodity price risks for both natural gas and crude oil and condensate wellhead prices. (See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Hedging Transactions.") In September 1992, the Company sold a volumetric production payment for $326.8 million to a limited partnership. Under the terms of the production payment agreements, the Company conveyed a real property interest in approximately 124 billion cubic feet equivalent ("Bcfe") (136 trillion British thermal units ("TBtu")) of certain natural gas and other hydrocarbons to the purchaser. Effective October 1, 1993, the agreements were amended providing for the extension of the original term of the volumetric production payment through March 31, 1999 and including a revised schedule of daily quantities of hydrocarbons to be delivered which is approximately one-half of the original schedule. The revised schedule under the amended agreement totals approximately 89.1 Bcfe (97.8 TBtu) versus approximately 87.9 Bcfe (96.4 TBtu) remaining to be delivered under the original agreement. Daily quantities of hydrocarbons no longer required to be delivered under the revised schedule during the period from October 1, 1993 through June 30, 1996 are 5
8 available for sale by the Company. The Company retains responsibility for its working interest share of the cost of operations. In March 1995, in a series of transactions with Enron Corp. and an affiliate of Enron Corp., the Company exchanged all of its fuel supply and purchase contracts and related price swap agreements associated with a Texas City cogeneration plant (the "Cogen Contracts") for certain natural gas price swap agreements (the "Swap Agreements") of equivalent value. As a result of the transactions, the Company has been relieved of all performance obligations associated with the Cogen Contracts. The Company will realize net operating revenues and receive corresponding cash payments of approximately $91 million during the period extending through December 31, 1999, under the terms of the Swap Agreements. The estimated fair value of the Swap Agreements was approximately $81 million at the date the Swap Agreements were received. The net effect of this series of transactions has resulted/will result in increases in net operating revenues and cash receipts for the Company during 1995 and 1996 of approximately $13 million and $7 million, respectively, with offsetting decreases in 1998 and 1999 versus that anticipated under the Cogen Contracts. 6
9 WELLHEAD VOLUMES AND PRICES, AND LEASE AND WELL EXPENSES The following table sets forth certain information regarding the Company's wellhead volumes of and average prices for natural gas per thousand cubic feet ("Mcf"), crude oil and condensate, and natural gas liquids per barrel ("Bbl"), and average lease and well expenses per thousand cubic feet equivalent ("Mcfe" - natural gas equivalents are determined using the ratio of 6.0 Mcf of natural gas to 1.0 barrel of crude oil and condensate or natural gas liquids) delivered during each of the three years in the period ended December 31, 1995: <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, ---------------------------- 1995 1994 1993 ------ ------ ------ <S> <C> <C> <C> VOLUMES (PER DAY) Natural Gas (MMcf) United States(1)............................................ 560 614 649 Canada...................................................... 76 72 58 Trinidad.................................................... 107 63 2 ------ ------ ------ Total.................................................. 743 749 709 ====== ====== ====== Crude Oil and Condensate (MBbl) United States............................................... 9.1 8.0 6.6 Canada...................................................... 2.4 2.0 2.2 Trinidad.................................................... 5.1 2.5 .1 India....................................................... 2.5 .1 - ------ ------ ------ Total.................................................. 19.1 12.6 8.9 ====== ====== ====== Natural Gas Liquids (MBbl) United States............................................... 1.0 .3 .2 Canada...................................................... .4 .4 .4 ------ ------ ------ Total.................................................. 1.4 .7 .6 ====== ====== ====== AVERAGE PRICES Natural Gas ($/Mcf) United States(2)............................................ $ 1.39 $ 1.71 $ 1.97 Canada...................................................... .97 1.42 1.34 Trinidad.................................................... .97 .93 .89 Composite.............................................. 1.29 1.62 1.92 Crude Oil and Condensate ($/Bbl) United States............................................... $17.32 $16.06 $16.96 Canada...................................................... 16.22 14.05 14.63 Trinidad.................................................... 16.07 15.50 14.36 India....................................................... 16.81 15.70 - Composite.............................................. 16.78 15.62 16.37 Natural Gas Liquids ($/Bbl) United States............................................... $11.88 $12.45 $13.85 Canada...................................................... 9.74 8.45 9.46 Composite.............................................. 11.31 9.90 11.12 LEASE AND WELL EXPENSES ($/MCFE) United States............................................... $ .19 $ .19 $ .18 Canada...................................................... .35 .34 .48 Trinidad.................................................... .15 .17 1.46 India(3).................................................... 1.25 .13 - Composite.............................................. .22 .20 .21 </TABLE> - --------------- (1) Includes 48 MMcf per day in 1995 and 1994, and 81 MMcf per day in 1993 delivered under the terms of a volumetric production payment agreement effective October 1, 1992, as amended. (2) Includes an average equivalent wellhead value of $.80 per Mcf in 1995, $1.27 per Mcf in 1994 and $1.57 per Mcf in 1993 for the volumes described in note (1), net of transportation costs. (3) Based on expense estimates for nine days of production for 1994. Expenses for 1995 includes certain nonrecurring startup costs. 7
10 OTHER NATURAL GAS MARKETING VOLUMES AND PRICES The following table sets forth certain information regarding the Company's volumes of natural gas delivered under other marketing and volumetric production payment arrangements, and resulting average per unit gross revenue and per unit amortization of deferred revenues along with associated costs during each of the three years in the period ended December 31, 1995. (See "Marketing" for a discussion of other natural gas marketing arrangements and agreements). <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, ---------------------------- 1995 1994 1993 ------ ------ ------ <S> <C> <C> <C> Volume (MMcf per day)(1)......................................... 264 324 293 Average Gross Revenue ($/Mcf)(2)................................. $ 1.88 $ 2.38 $ 2.57 Associated Costs ($/Mcf)(3)(4)................................... 1.51 2.06 2.32 ------ ------ ------ Margin ($/Mcf)................................................... $ .37 $ .32 $ .25 ====== ====== ====== </TABLE> - --------------- (1) Includes 48 MMcf per day in 1995 and 1994 and 81 MMcf per day in 1993 delivered under the terms of volumetric production payment and exchange agreements effective October 1, 1992, as amended. (2) Includes per unit deferred revenue amortization for the volumes detailed in note (1) at an equivalent of $2.46 per Mcf ($2.36 per million British thermal units ("MMBtu")) in 1995 and 1994 and $2.50 per Mcf ($2.40 per MMBtu) in 1993. (3) Includes an average value of $1.57 per Mcf in 1995, $1.92 per Mcf in 1994 and $2.20 per Mcf in 1993, for the volumes detailed in note (1) including average wellhead value and any transportation costs and exchange differentials. (4) Including transportation and exchange differentials. COMPETITION The Company actively competes for reserve acquisitions and exploration/exploitation leases, licenses and concessions, frequently against companies with substantially larger financial and other resources. To the extent the Company's exploration budget is lower than that of certain of its competitors, the Company may be disadvantaged in effectively competing for certain reserves, leases, licenses and concessions. Competitive factors include price, contract terms, and quality of service, including pipeline connection times and distribution efficiencies. In addition, the Company faces competition from other producers and suppliers, including competition from other world wide energy supplies, such as natural gas from Canada. REGULATION Domestic Regulation of Natural Gas and Crude Oil Production. Natural gas and crude oil production operations are subject to various types of regulation, including regulation in the United States by state and federal agencies. Domestic legislation affecting the oil and gas industry is under constant review for amendment or expansion. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations which, among other things, require permits for the drilling of wells, regulate the spacing of wells, prevent the waste of natural gas and liquid hydrocarbon resources through proration and restrictions on flaring, require drilling bonds and regulate environmental and safety matters. The regulatory burden on the oil and gas industry increases its cost of doing business and, consequently, affects its profitability. A substantial portion of the Company's oil and gas leases in the Big Piney area and in the Gulf of Mexico, as well as some in other areas, are granted by the federal government and administered by the Bureau of Land Management (the "BLM") and the Minerals Management Service (the "MMS") federal agencies. Operations conducted by the Company on federal oil and gas leases must comply with numerous statutory and 8
11 regulatory restrictions concerning the above and other matters. Certain operations must be conducted pursuant to appropriate permits issued by the BLM and the MMS. Sales of crude oil, condensate and natural gas liquids by the Company are made at unregulated market prices. The transportation and sale for resale of natural gas in interstate commerce are regulated pursuant to the Natural Gas Act of 1938 (the "NGA") and the Natural Gas Policy Act of 1978 (the "NGPA"). These statutes are administered by the Federal Energy Regulatory Commission (the "FERC"). Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act of 1989 deregulated natural gas prices for all "first sales" of natural gas, which includes all sales by the Company of its own production. Consequently, sales of the Company's natural gas currently may be made at market prices, subject to applicable contract provisions. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and nondiscriminatory basis. These efforts have significantly altered the marketing and pricing of natural gas. Commencing in April 1992, the FERC issued Order Nos. 636, 636A and 636B ("Order No. 636"), which mandate a fundamental restructuring of interstate natural gas pipeline sales and transportation services, including the "unbundling" by interstate natural gas pipelines of the sales, transportation, storage, and other components of their previously existing city-gate sales service, and to separately state the rates for each unbundled service. Under Order No. 636, unbundled pipeline sales can be made only in the production areas. The purpose of Order No. 636 is to further enhance competition in the natural gas industry by assuring the comparability of pipeline sales service and services offered by a pipelines' competitors. The FERC issued final orders accepting most pipelines' Order No. 636 compliance filings, and has commenced a series of one-year reviews of individual pipeline implementations of Order No. 636. Appeals are pending and these orders may be amended or reversed in whole or in part. Order No. 636 does not directly regulate the Company's activities, but has had and will have an indirect effect because of its broad scope. With Order No. 636 and pending ongoing FERC reviews of individual pipeline restructurings, subject to court review, it is difficult to predict with precision its effects. In many instances, however, Order No. 636 has substantially reduced or brought to an end interstate pipelines' traditional roles as wholesalers of natural gas in favor of providing only storage and transportation services. Order No. 636 has also substantially increased competition in natural gas markets, even though there remains significant uncertainty with respect to the marketing and transportation of natural gas. In spite of this uncertainty, Order No. 636 may enhance the Company's ability to market and transport its natural gas production, although it may also subject the Company to more restrictive pipeline imbalance tolerances and greater penalties for violation of such tolerances. In July 1994, the FERC eliminated a regulation that had rendered virtually all sales of natural gas by pipeline affiliates, such as the Company, to be deregulated first sales. As a result, only sales by the Company of its own production now qualify for this status. All other sales of natural gas by the Company, such as those of natural gas purchased from third parties, are now jurisdictional sales subject to a blanket sales certificate issued by the FERC under the NGA. The Company does not anticipate this change will have any significant current adverse effects in light of the flexible terms and conditions of the existing blanket certificate. Such sales are subject to the future possibility of greater federal oversight, however, including the possibility the FERC might prospectively impose more restrictive conditions on such sales. The FERC has extended indefinitely its regulations (Order No. 497 regulations) governing relationships between interstate pipelines and their marketing affiliates, subject to revisions to delete an out-of-date standard and revise certain reporting and record keeping requirements. Among other matters, these new rules require pipelines to post on their electronic bulletin boards, within 24 hours of gas flow, information concerning discounted transportation provided to marketing affiliates to enable competing marketers to request comparable discounts. Order No. 497 does not directly regulate the Company's activities, although a substantial portion of the Company's natural gas production is sold to or transported by interstate pipeline affiliates which are subject to the Order. The Company's activities may therefore be indirectly affected by these regulations. 9
12 The Company owns, directly or indirectly, certain natural gas pipelines that it believes meet the traditional tests the FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction under the NGA. State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels as the pipeline restructuring under Order No. 636 is implemented. For example, the State of Oklahoma in 1995 enacted legislation that essentially requires gatherers to provide open access, non-discriminatory service. In addition, the FERC has reiterated that, except in situations in which the gatherer acts in concert with an interstate pipeline affiliate to frustrate the FERC's transportation policies, it does not have jurisdiction over natural gas gathering facilities and services and that such facilities and services are properly regulated by state authorities. This FERC action may further encourage regulatory scrutiny of natural gas gathering by state agencies. In addition, the FERC has approved several transfers by interstate pipelines, including certain of the Company's pipeline affiliates, of gathering facilities to unregulated independent or affiliated gathering companies. This could increase competition among gatherers in the affected areas. Certain of the FERC's orders delineating its new gathering policy are subject to pending court appeals. The Company's gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. The FERC has recently announced its intention to reexamine certain of its transportation-related policies, including the manner in which interstate pipelines release transportation capacity under Order No. 636, and has announced new policies concerning the use of alternative, non-cost based methods for setting rates for interstate natural gas transmission. While any resulting FERC action would affect the Company only indirectly, these inquiries are intended to further enhance competition in natural gas markets. The FERC has also recently initiated a proceeding in which it intends to evaluate its current regulatory treatment of pipeline facilities constructed in offshore federal waters. The ultimate outcome of such proceeding cannot be predicted at this time, but it is possible that it could result in more active oversight by the FERC of such offshore facilities. The Company's natural gas gathering operations may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement, and management of facilities. Pipeline safety issues have recently become the subject of increasing focus in various political and administrative arenas at both the state and federal levels. For example, federal legislation addressing pipeline safety issues was considered during 1994 and 1995, which, if enacted, would have included a federal "one-call" notification system and certain new facilities specifications applicable to certain new construction. Similar "one call" legislation has been reintroduced in the U.S. Congress. The Company cannot predict what effect, if any, the adoption of this or other additional pipeline safety legislation might have on its operations, but does not believe that any adverse effect would be material. The Company cannot predict the effect that any of the aforementioned orders or the challenges to such orders will ultimately have on the Company's operations. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC and the courts. The Company cannot predict when or whether any such proposals or proceedings may become effective. It should also be noted that the natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less regulated approach currently being pursued by the FERC will continue indefinitely. Thus, the Company cannot predict the ultimate outcome or durability of the unbundled regulatory regime mandated by Order No. 636. Environmental Regulation. Various federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect the Company's operations and costs as a result of their effect on natural gas and crude oil exploration, development and production operations. It is not anticipated that the Company will be required in the near future to expend amounts that are material in relation to its total exploration and development expenditure program by reason of environmental laws and regulations, but inasmuch as such laws and regulations are frequently changed, the Company is unable to predict the ultimate cost of compliance. 10
13 Canadian Regulation. In Canada, the petroleum industry operates under federal, provincial and municipal legislation and regulations governing land tenure, royalties, production rates, pricing, environmental protection, exports and other matters. The price of natural gas and crude oil in Canada has been deregulated and is now determined by market conditions and negotiations between buyers and sellers. Various matters relating to the transportation and export of natural gas continue to be subject to regulation by both provincial and federal agencies; however, the North American Free Trade Agreement has reduced the risk of altering cross-border commercial transactions. Canadian governmental regulations may have a material effect on the economic parameters for engaging in oil and gas activities in Canada and may have a material effect on the advisability of investments in Canadian oil and gas drilling activities. The Company is monitoring political, regulatory and economic developments in Canada. Other International Regulation. The Company's exploration and production operations outside North America are subject to various types of regulations imposed by the respective governments of the countries in which the Company's operations are conducted, and may affect the Company's operations and costs within that country. The Company currently has producing operations offshore Trinidad and India and exploration activities in other selected international areas. RELATIONSHIP BETWEEN THE COMPANY AND ENRON CORP. Ownership of Common Stock. Through its ability to elect all of the directors of the Company, Enron Corp. has the ability to control all matters relating to the management of the Company, including any determination with respect to acquisition or disposition of Company assets, future issuance of common stock or other securities of the Company and any dividends payable on the common stock. Enron Corp. also has the ability to control the Company's exploration, development, acquisition and operating expenditure plans. There is no agreement between Enron Corp. and the Company that would prevent Enron Corp. from acquiring additional shares of common stock of the Company. The closing on December 13, 1995 of the sale by Enron Corp. of approximately 31 million outstanding shares of the common stock of the Company reduced Enron Corp.'s ownership interest in the Company from 80% to 61% with the result that (i) the Company ceased, effective December 14, 1995, to be included in the consolidated federal income tax return filed by Enron Corp. and (ii) the tax allocation agreement previously in effect between the Company and Enron Corp. was terminated. In addition, effective December 14, 1995, the Company and its subsidiaries and Enron Corp. entered into a new tax allocation agreement pursuant to which, among other things, Enron Corp. has agreed (in exchange for the payment of $13.0 million by the Company) to be liable for, and indemnify the Company against, all U.S. federal and state income taxes and certain foreign taxes imposed on the Company for periods prior to the date Enron Corp. reduced its ownership in the Company to less than 80%. The Company does not believe that the cessation of consolidated tax reporting with Enron Corp., the termination of the tax allocation agreement concurrent with deconsolidation and the signing of the new tax allocation agreement with Enron Corp. will have a material adverse effect on its financial condition or results of operations. Contractual Arrangements. The Company entered into a Services Agreement (the "Services Agreement") with Enron Corp. effective January 1, 1994, pursuant to which Enron Corp. provides various services, such as maintenance of certain employee benefit plans, provision of telecommunications and computer services, lease of office space and the provision of purchasing and operating services and certain other corporate staff and support services. Such services historically have been supplied to the Company by Enron Corp., and the Services Agreement provides for the further delivery of such services substantially identical in nature and quality to those services previously provided. The Company has agreed to a fixed rate for the rental of office space and to reimburse Enron Corp. for all other direct costs incurred in rendering services to the Company under the contract and to pay Enron Corp. for allocated indirect costs incurred in rendering such services up to a maximum of approximately $7 million in 1995 and $6.7 million for 1994. The limit on cost for the allocated indirect services provided by Enron Corp. to the Company will increase in subsequent years for inflation and certain changes in the Company's allocation bases, but such increase will not exceed 7.5% per 11
14 year. The Services Agreement is for an initial term of five years through December 1998 and will continue thereafter until terminated by either party. In March 1995, in a series of transactions with Enron Corp. and an affiliate of Enron Corp., the Company exchanged all of its fuel supply and purchase contracts and related price swap agreements associated with a Texas City cogeneration plant (the "Cogen Contracts") for certain natural gas price swap agreements (the "Swap Agreements") of equivalent value. As a result of the transactions, the Company has been relieved of all performance obligations associated with the Cogen Contracts. The Company will realize net operating revenues and receive corresponding cash payments of approximately $91 million during the period extending through December 31, 1999 under the terms of the Swap Agreements. The estimated fair value of the Swap Agreements was approximately $81 million at the date the Swap Agreements were received. The net effect of this series of transactions has resulted/will result in increases in net operating revenues and cash receipts for the Company during 1995 and 1996 of approximately $13 million and $7 million, respectively, with offsetting decreases in 1998 and 1999 versus that anticipated under the Cogen Contracts. Prior to December 14, 1995, the Company was included in the consolidated federal income tax return filed by Enron Corp. as the common parent for itself and its subsidiaries, excluding any foreign subsidiaries, and the resulting taxes, including taxes for any state or other taxing jurisdiction that required or permitted a consolidated, combined, or unitary tax return to be filed and in which the Company and/or any of its subsidiaries was included, were apportioned as between the Company and/or any of its subsidiaries and Enron Corp. based on the terms of the tax allocation agreement in effect prior to December 14, 1995. Effective December 14, 1995, the Company and its subsidiaries and Enron Corp. entered into a new tax allocation agreement (See "Ownership of Common Stock"). Conflicts of Interest. The nature of the respective businesses of the Company and Enron Corp. and its affiliates is such as to potentially give rise to conflicts of interest between the two companies. Conflicts could arise, for example, with respect to transactions involving purchases, sales and transportation of natural gas and other business dealings between the Company and Enron Corp. and its affiliates, potential acquisitions of businesses or oil and gas properties, the issuance of additional shares of voting securities, the election of directors or the payment of dividends by the Company. Circumstances may also arise that would cause Enron Corp. to engage in the exploration for and/or development and production of natural gas and crude oil in competition with the Company. For example, opportunities might arise which would require financial resources greater than those available to the Company, which are located in areas or countries in which the Company does not intend to operate or which involve properties that the Company would be unwilling to acquire. Also, Enron Corp. might acquire a competing oil and gas business as part of a larger acquisition. In addition, as part of Enron Corp.'s strategy of securing supplies of natural gas or capital, Enron Corp. may from time to time acquire producing properties or interests in entities owning producing properties, and thereafter engage in exploration, development and production activities with respect to such properties or indirectly engage in such activities through such companies. Enron Corp. subsidiaries provide or arrange financing, including debt or equity financing, for exploration and production companies that compete with the Company. In connection with such activities, Enron Corp. affiliates may make investments in the debt or equity of such companies. There are currently no such transactions under consideration that would result in voting control by Enron Corp. or any of its affiliates, other than the transaction described below. In its financing activities, Enron Corp. or an entity in which it has an interest may make loans secured by oil and gas properties or securities of oil and gas companies, may acquire production payments or may receive interests in oil and gas properties as equity components of lending transactions. As a result of its lending activities, Enron Corp. may also acquire oil and gas properties or companies upon foreclosure of secured loans or as part of a borrower's rearrangement of its obligations. Such acquisition, exploration, development and production activities may directly or indirectly compete with the Company's business. There can be no assurances that Enron Corp. will not engage directly or indirectly through entities other than the Company, in the natural gas and crude oil exploration, development and production business in competition with the Company. 12
15 Joint Energy Development Investments Limited Partnership ("JEDI"), a limited partnership in which Enron Capital & Trade Resources Corp. ("ECT"), a wholly-owned subsidiary of Enron Corp., owns a 50% general partner interest, has entered into an agreement to acquire a controlling interest in Coda Energy, Inc. ("Coda"). Coda is engaged in the exploration for, and the development, production and marketing of, natural gas and crude oil primarily in North Texas and Oklahoma. Crude oil accounts for approximately 86% of Coda's proved reserves. At December 31, 1994, Coda reported estimated proved natural gas reserves of 39,808 MMcf and estimated proved crude oil, condensate and natural gas liquids reserves of 39,207 MBbls. Enron Corp. anticipates that the transaction will be consummated in early 1996, subject to Coda stockholder approval and other conditions. Conflicts may arise between Coda and JEDI, and if the acquisition of Coda occurs Enron Corp. will be required to resolve such conflicts in a manner that is consistent with its fiduciary and contractual duties to other investors in Coda and JEDI and its fiduciary duties to the Company. ECT has entered into an agreement with JEDI and other investors in Coda designed to minimize certain conflicts of interest that may arise and providing, among other things, that the Company has no obligation to offer any business opportunities to Coda. The Company and Enron Corp. and its affiliates have in the past entered into material intercompany transactions and agreements incident to their respective businesses, and the Company and Enron Corp. and its affiliates may be expected to enter into material transactions and agreements from time to time in the future. Such transactions and agreements have related to, among other things, the purchase and sale of natural gas and crude oil, the financing of exploration and development efforts by the Company, and the provision of certain corporate services. (See "Marketing" and the Consolidated Financial Statements and notes thereto). The Company believes that its existing transactions and agreements with Enron Corp. and its affiliates have been at least as favorable to the Company as could be obtained from third parties, and the Company intends that the terms of any future transactions and agreements between the Company and Enron Corp. and its affiliates will be at least as favorable to the Company as could be obtained from third parties. OTHER MATTERS Energy Prices. Since the Company is primarily a natural gas company, it is more significantly impacted by changes in natural gas prices than in the prices for crude oil, condensate and natural gas liquids. During recent periods, domestic natural gas has been priced significantly below parity with crude oil, condensate and natural gas liquids based on the energy equivalency of, and differences in transportation and processing costs associated with, the respective products. This imbalance in parity has been primarily driven by, among other things, a supply of domestic natural gas volumes in excess of demand requirements. The Company is unable to predict when this supply imbalance may be resolved due to the significant impacts of factors such as general economic conditions, technology developments, weather and other international energy supplies over which the Company has no control. Average North America wellhead natural gas prices have fluctuated, at times rather dramatically, during the last three years. While these fluctuations resulted in an increase in average wellhead natural gas prices realized by the Company of 22% from 1992 to 1993, the average North America natural gas price received by the Company decreased 13% from 1993 to 1994 and 20% from 1994 to 1995. Wellhead natural gas volumes from Trinidad are sold at prices that are based on a fixed schedule with periodic escalations. While natural gas deliveries in India are not expected to commence until 1997 under the terms of the Production Sharing Contract, the price of such deliveries, when initiated, is to be indexed to a basket of world market fuel oil quotations structured to include floor and ceiling limits. Due to the many uncertainties associated with the world political environment, the availabilities of other world wide energy supplies and the relative competitive relationships of the various energy sources in the view of the consumers, the Company is unable to predict what changes may occur in natural gas prices in the future. Substantially all of the Company's wellhead crude oil and condensate is sold under various terms and arrangements at market responsive prices. Crude oil and condensate prices also have fluctuated during the last three years. Due to the many uncertainties associated with the world political environment, the availabilities of other world wide energy supplies and the relative competitive relationships of the various energy sources in the 13
16 view of the consumers, the Company is unable to predict what changes may occur in crude oil and condensate prices in the future. To mitigate the risk of market price fluctuations, the Company engages in certain price risk management activities to hedge commodity prices associated with a portion of the Company's sales and purchases of natural gas and crude oil. (See "Management's Discussion and Analysis of Financial Condition and Results of Operations"). Tight Gas Sand Tax Credits (Section 29) and Severance Tax Exemption. Federal United States tax law provides a tax credit for production of certain fuels produced from nonconventional sources (including natural gas produced from tight formations), subject to a number of limitations. Fuels qualifying for the credit must be produced from a well drilled or a facility placed in service after November 5, 1990 and before January 1, 1993, and must be sold before January 1, 2003. The credit, which is currently approximately $.52 per MMBtu of natural gas, is computed by reference to the price of crude oil, and is phased out as the price of crude oil exceeds $23.50 in 1980 dollars (adjusted for inflation) with complete phaseout if such price exceeds $29.50 in 1980 dollars (similarly adjusted). Under this formula, the commencement of phaseout would be triggered if the average price for crude oil rose above approximately $45 per barrel in current dollars. Significant benefits from the tax credit are accruing to the Company since a portion (and in some cases a substantial portion) of the Company's natural gas production from new wells drilled after November 5, 1990, and before January 1, 1993, on the Company's leases in several of the Company's significant producing areas qualify for this tax credit. Natural gas production from wells spudded or completed after May 24, 1989 and before September 1, 1996 in tight formations in a certain state qualifies for a ten-year exemption, ending August 31, 2001, from severance taxes, subject to certain limitations. In 1995, the drilling qualification period was extended in a modified and somewhat reduced form from September 1996 through August 2002. Consequently, new qualifying production will be added prospectively to that presently qualified. Other. All of the Company's oil and gas activities are subject to the risks normally incident to the exploration for and development and production of natural gas and crude oil, including blowouts, cratering and fires, each of which could result in damage to life and property. Offshore operations are subject to usual marine perils, including hurricanes and other adverse weather conditions, and governmental regulations as well as interruption or termination by governmental authorities based on environmental and other considerations. In accordance with customary industry practices, insurance is maintained by the Company against some, but not all, of the risks. Losses and liabilities arising from such events could reduce revenues and increase costs to the Company to the extent not covered by insurance. The Company's operations outside of North America are subject to certain risks, including expropriation of assets, risks of increases in taxes and government royalties, renegotiation of contracts with foreign governments, political instability, payment delays, limits on allowable levels of production and current exchange and repatriation losses, as well as changes in laws, regulations and policies governing operations of foreign companies generally. 14
17 CURRENT EXECUTIVE OFFICERS OF THE REGISTRANT The current executive officers of the Company and their names and ages are as follows: <TABLE> <CAPTION> NAME AGE POSITION ---- --- -------- <S> <C> <C> Forrest E. Hoglund................... 62 Chairman of the Board, President and Chief Executive Officer; Director Joe Michael McKinney................. 56 President - International Operations Dennis M. Ulak....................... 42 President - International Operations Mark G. Papa......................... 49 President - North American Operations Lewis P. Chandler, Jr................ 56 Senior Vice President, Law Walter C. Wilson..................... 53 Senior Vice President and Chief Financial Officer Ben B. Boyd.......................... 54 Vice President and Controller </TABLE> Forrest E. Hoglund joined the Company as Chairman of the Board, Chief Executive Officer and Director in September 1987. Since May 1990, he has also served as President of the Company. Mr. Hoglund was a director of USX Corporation from February 1986 until September 1987. He joined Texas Oil & Gas Corp. ("TXO") in 1977 as president, was named Chief Operating Officer in 1979, Chief Executive Officer in 1982, and served TXO in those capacities until September 1987. Mr. Hoglund is also a director of Texas Commerce Bancshares, Inc. Joe Michael McKinney has been President - International Operations since February 1994, a dual position shared with Mr. Ulak effective January 1996, with responsibilities for exploration, drilling, production and engineering activities for the Company's ventures outside North America. Mr. McKinney joined the Company and was named Senior Vice President of Operations for Enron Oil & Gas International, Inc., a wholly-owned subsidiary of the Company, in December 1991. He was elected President and Chief Operating Officer of Enron Oil & Gas International, Inc. in April 1993, a capacity in which he continues to serve jointly with Mr. Ulak effective January 1996. Prior to joining the Company, Mr. McKinney held operations management positions with Union Texas Petroleum Company, The Superior Oil Company and Exxon Company, USA. Dennis M. Ulak has been President - International Operations, a dual position shared with Mr. McKinney, since January 1996 with responsibilities for exploration, drilling, production and engineering activities for the Company's ventures outside North America. Mr. Ulak also serves jointly with Mr. McKinney as President and Chief Operating Officer of Enron Oil & Gas International, Inc. Mr. Ulak joined the Company in March 1987 as Senior Counsel and was named Assistant General Counsel for the Company's international operations in February 1989, Assistant General Counsel for the Company in August 1990 and Vice President and General Counsel for the Company in March 1992. Prior to joining the Company, Mr. Ulak held various legal positions with Enron Corp. and Northern Natural Gas Company. Mark G. Papa has been President - North American Operations since February 1994. From May 1986 through January 1994, Mr. Papa served as Senior Vice President - Operations. Mr. Papa joined Belco Petroleum Corporation, a predecessor of the Company, in 1981 as Division Production Coordinator and served as Senior Vice President - Drilling and Production, BelNorth Petroleum Corporation from May 1984 until May 1986. Lewis P. Chandler, Jr. has been Senior Vice President, Law since March 1992. Mr. Chandler joined the Company in December 1973 and has since served in a number of positions in the Company's legal department. He was appointed Vice President and General Counsel for BelNorth Petroleum Corp. in June 1983 and was named Vice President and General Counsel for the Company in January 1987. From May 1991 until March 1992, he was Senior Vice President and General Counsel for the Company. Walter C. Wilson has been Senior Vice President and Chief Financial Officer since May 1991. Mr. Wilson joined the Company in November 1987 as Vice President and Controller and was named Senior 15
18 Vice President - Finance in October 1988. Prior to joining the Company Mr. Wilson held financial management positions with Exxon Company, USA for 16 years and The Superior Oil Company for 4 years. Ben B. Boyd has been Vice President and Controller since March 1991. Mr. Boyd joined the Company in March 1989 as Director of Accounting and was named Controller in May 1990. Prior to joining the Company, Mr. Boyd held financial management positions with DeNovo Oil & Gas, Inc., Scurlock Oil Company and Coopers & Lybrand. ITEM 2. PROPERTIES OIL AND GAS EXPLORATION AND PRODUCTION PROPERTIES AND RESERVES Reserve Information. For estimates of the Company's net proved and proved developed reserves of natural gas and liquids, including crude oil, condensate and natural gas liquids, see "Supplemental Information to Consolidated Financial Statements." There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth in Supplemental Information to Consolidated Financial Statements represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and liquids, including crude oil, condensate and natural gas liquids, that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the amount and quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers normally vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities ultimately recovered. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based. In general, the volume of production from oil and gas properties owned by the Company declines as reserves are depleted. Except to the extent the Company acquires additional properties containing proved reserves or conducts successful exploration and development activities, or both, the proved reserves of the Company will decline as reserves are produced. Volumes generated from future activities of the Company are therefore highly dependent upon the level of success in acquiring or finding additional reserves and the costs incurred in doing so. The Company's estimates of reserves filed with other federal agencies agree with the information set forth in Supplemental Information to Consolidated Financial Statements. 16
19 Acreage. The following table summarizes the Company's developed and undeveloped acreage at December 31, 1995. Excluded is acreage in which the Company's interest is limited to owned royalty, overriding royalty and other similar interests. <TABLE> <CAPTION> DEVELOPED UNDEVELOPED TOTAL -------------------- --------------------- --------------------- GROSS NET GROSS NET GROSS NET --------- -------- --------- --------- --------- --------- <S> <C> <C> <C> <C> <C> <C> United States California................ 10,215 6,368 638,199 637,454 648,414 643,822 Offshore Gulf of Mexico... 315,745 132,505 455,133 352,577 770,878 485,082 Texas..................... 454,256 221,207 272,990 214,233 727,246 435,440 Wyoming................... 161,867 117,815 316,330 246,758 478,197 364,573 Oklahoma.................. 214,363 72,279 106,074 58,162 320,437 130,441 New Mexico................ 75,487 35,056 88,013 47,924 163,500 82,980 Utah...................... 57,820 46,512 35,863 30,365 93,683 76,877 Kansas.................... 14,176 9,498 25,055 22,766 39,231 32,264 Colorado.................. 9,153 1,447 35,006 16,755 44,159 18,202 Michigan.................. 11 10 14,213 13,650 14,224 13,660 Mississippi............... 2,490 1,853 12,171 8,445 14,661 10,298 Montana................... 1,301 1,169 2,082 1,075 3,383 2,244 Other..................... 15,225 2,831 10,986 5,204 26,211 8,035 --------- --------- ---------- ---------- ---------- ---------- Total............. 1,332,109 648,550 2,012,115 1,655,368 3,344,224 2,303,918 Canada Alberta................... 364,328 168,503 192,429 146,739 556,757 315,242 Saskatchewan.............. 179,343 155,588 222,975 199,604 402,318 355,192 Manitoba.................. 11,531 9,702 480 480 12,011 10,182 British Columbia.......... 656 164 - - 656 164 --------- --------- ---------- ---------- ---------- ---------- Total Canada...... 555,858 333,957 415,884 346,823 971,742 680,780 Other International Australia................. - - 9,600,000 4,800,000 9,600,000 4,800,000 China..................... - - 1,208,805 604,403 1,208,805 604,403 Russia.................... - - 1,425,000 712,500 1,425,000 712,500 France.................... - - 1,063,925 1,063,925 1,063,925 1,063,925 India..................... 60,000 18,000 602,207 180,662 662,207 198,662 Trinidad.................. 4,200 3,990 74,851 71,108 79,051 75,098 United Kingdom............ - - 173,600 86,800 173,600 86,800 --------- --------- ---------- ---------- ---------- ---------- Total Other International... 64,200 21,990 14,148,388 7,519,398 14,212,588 7,541,388 --------- --------- ---------- ---------- ---------- ---------- Total........ 1,952,167 1,004,497 16,576,387 9,521,589 18,528,554 10,526,086 ========= ========= ========== ========== ========== ========== </TABLE> Producing Well Summary. The following table reflects the Company's ownership in gas and oil wells located in Texas, the Gulf of Mexico, Oklahoma, New Mexico, Utah, Wyoming, and various other states, Canada, Trinidad and India at December 31, 1995. Gross oil and gas wells include 205 with multiple completions. <TABLE> <CAPTION> PRODUCTIVE WELLS --------------- GROSS NET ----- ----- <S> <C> <C> Gas.................................................. 4,627 3,170 Oil.................................................. 774 435 ----- ----- Total...................................... 5,401 3,605 ===== ===== </TABLE> 17
20 Drilling and Acquisition Activities. During the years ended December 31, 1995, 1994 and 1993 the Company spent approximately $513.8, $493.9 and $430.1 million, respectively, for exploratory and development drilling and acquisition of leases and producing properties. The Company drilled, participated in the drilling of or acquired wells as set out in the table below for the periods indicated: <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, ----------------------------------------------------- 1995 1994 1993 --------------- --------------- --------------- GROSS NET GROSS NET GROSS NET ----- ------ ----- ------ ----- ------ <S> <C> <C> <C> <C> <C> <C> Development Wells Completed Domestic Gas....................................... 220 146.38 308 244.23 352 279.00 Oil....................................... 60 49.93 34 29.57 45 19.01 Dry....................................... 47 37.33 41 32.15 59 46.83 --- ------ --- ------ --- ------ Total................................ 327 233.64 383 305.95 456 344.84 International Gas....................................... 117 107.53 250 190.30 227 190.10 Oil....................................... 12 8.08 11 5.10 4 3.50 Dry....................................... 15 12.83 13 11.50 11 7.60 --- ------ --- ------ --- ------ Total................................ 144 128.44 274 206.90 242 201.20 --- ------ --- ------ --- ------ Total Development............................ 471 362.08 657 512.85 698 546.04 --- ------ --- ------ --- ------ Exploratory Wells Completed Domestic Gas....................................... 4 3.14 13 9.80 14 10.03 Oil....................................... 7 3.28 3 2.57 3 2.50 Dry....................................... 15 10.29 23 18.17 32 22.08 --- ------ --- ------ --- ------ Total................................ 26 16.71 39 30.54 49 34.61 International Gas....................................... 7 5.89 9 7.90 14 11.40 Oil....................................... 1 .33 1 .50 2 .90 Dry....................................... 6 2.99 14 12.50 10 7.35 --- ------ --- ------ --- ------ Total................................ 14 9.21 24 20.90 26 19.65 --- ------ --- ------ --- ------ Total Exploratory............................ 40 25.92 63 51.44 75 54.26 --- ------ --- ------ --- ------ Total................................ 511 388.00 720 564.29 773 600.30 Wells in Progress at end of period............. 52 32.71 45 28.79 82 61.09 --- ------ --- ------ --- ------ Total................................ 563 420.71 765 593.08 855 661.39 === ====== === ====== === ====== Wells Acquired Gas....................................... 277 101.70* 41 40.90* 44 26.44* Oil....................................... 5 .46 60 38.99* - 12.80* --- ------ --- ------ --- ------ Total................................ 282 102.16 101 79.89 44 39.24 === ====== === ====== === ====== </TABLE> - --------------- * Includes the acquisition of additional interests in certain wells in which the Company previously held an interest. All of the Company's drilling activities are conducted on a contract basis with independent drilling contractors. The Company owns no drilling equipment. 18
21 ITEM 3. LEGAL PROCEEDINGS The Company and its subsidiaries and related companies are named defendants in numerous lawsuits and named parties in numerous governmental proceedings arising in the ordinary course of business. While the outcome of lawsuits or other proceedings against the Company cannot be predicted with certainty, management does not expect these matters to have a material adverse effect on the financial condition or results of operations of the Company. On November 19, 1992, TransAmerican Natural Gas Corporation ("TransAmerican") filed a petition against the Company alleging breach of contract, tortious interference with contract, misappropriation of trade secrets and violation of state antitrust laws. The petition, as amended, sought actual damages of at least $100 million plus exemplary damages of $300 million. The Company filed counterclaims against TransAmerican and a third-party claim against its sole shareholder, John R. Stanley, alleging fraud, negligent misrepresentation and breach of state antitrust laws. On October 16, 1995, the Company, TransAmerican and Stanley entered into an agreement which resolved all claims. The settlement terms did not have a materially adverse effect on the Company's financial condition or results of operations. The suit was dismissed with prejudice as to all parties by order entered in November 1995. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS There were no matters submitted to a vote of security holders during the fourth quarter of 1995. 19
22 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER MATTERS The following table sets forth, for the periods indicated, the high and low sale prices per share for the common stock of the Company, as reported on the New York Stock Exchange Composite Tape, and the amount of cash dividends paid per share. The 1993 and First and Second Quarter 1994 sales prices and cash dividends per share have been restated to reflect a two-for-one stock split on May 31, 1994. <TABLE> <CAPTION> PRICE RANGE ----------------- CASH HIGH LOW DIVIDENDS ------ ------ --------- <S> <C> <C> <C> 1993 First Quarter......................................... $20.31 $13.38 $.030 Second Quarter........................................ 22.50 17.88 .030 Third Quarter......................................... 26.81 19.88 .030 Fourth Quarter........................................ 27.00 17.06 .030 1994 First Quarter......................................... $23.75 $19.31 $.030 Second Quarter........................................ 24.63 22.38 .030 Third Quarter......................................... 23.00 18.50 .030 Fourth Quarter........................................ 22.75 17.38 .030 1995 First Quarter......................................... $24.88 $17.13 $.030 Second Quarter........................................ 24.75 20.25 .030 Third Quarter......................................... 25.38 20.00 .030 Fourth Quarter........................................ 24.88 18.75 .030 </TABLE> As of March 1, 1996, there were approximately 275 record holders of the Company's common stock, including individual participants in security position listings. There are an estimated 9,000 beneficial owners of the Company's common stock, including shares held in street name. Following the initial public offering and sale of its common stock in October 1989, the Company paid quarterly dividends of $0.025 per share beginning with an initial dividend paid in January 1990 with respect to the fourth quarter of 1989. Beginning in January 1993 with respect to the fourth quarter of 1992, the Company has paid quarterly dividends of $0.03 per share. The Company currently intends to continue to pay quarterly cash dividends on its outstanding shares of common stock. However, the determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, the financial condition, funds from operations, level of exploration and development expenditure opportunities and future business prospects of the Company. 20
23 ITEM 6. SELECTED FINANCIAL DATA <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, ----------------------------------------------------------------- 1995 1994 1993 1992 1991 --------- --------- --------- --------- --------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) <S> <C> <C> <C> <C> <C> STATEMENT OF INCOME DATA: Net operating revenues....... $ 648,702 $ 625,823 $ 581,020 $ 459,026 $ 402,588 Operating expenses Lease and well............. 69,463 60,384 59,344 49,406 49,922 Exploration................ 42,044 41,811 36,921 33,278 31,470 Dry hole................... 12,911 17,197 18,355 10,764 14,698 Impairment of unproved oil and gas properties...... 23,715 24,936 20,467 15,136 12,791 Depreciation, depletion and amortization............ 216,047 242,182 249,704 179,839 160,885 General and administrative.......... 56,626 51,418 45,274 36,648 36,216 Taxes other than income.... 32,587 28,254 35,396 28,346 18,222 --------- --------- --------- --------- --------- Total.............. 453,393 466,182 465,461 353,417 324,204 --------- --------- --------- --------- --------- Operating income............. 195,309 159,641 115,559 105,609 78,384 Other income, net............ 669 2,783 6,635 (3,476) (3,215) Interest expense (net of interest capitalized)...... 11,924 8,489 9,921 22,289 29,500 --------- --------- --------- --------- --------- Income before income taxes... 184,054 153,935 112,273 79,844 45,669 Income tax provision (benefit)(1)............... 41,936(2) 5,937(3) (25,752)(4) (17,736) (2,247) --------- --------- --------- --------- --------- Net income................... $ 142,118 $ 147,998 $ 138,025 $ 97,580 $ 47,916 ========= ========= ========= ========= ========= Earnings per share of common stock(5)................... $ .89 $ .93 $ .86 $ .63 $ .32 ========= ========= ========= ========= ========= Average number of common shares(5).................. 159,917 159,845 159,966 154,533 151,800 ========= ========= ========= ========= ========= </TABLE> <TABLE> <CAPTION> AT DECEMBER 31, ------------------------------------------------------------------ 1995 1994 1993 1992 1991 ---------- ---------- ---------- ---------- ---------- (IN THOUSANDS) <S> <C> <C> <C> <C> <C> BALANCE SHEET DATA: Oil and gas properties - net........... $1,881,545 $1,684,811 $1,546,045 $1,468,011 $1,339,666 Total assets................. 2,147,258 1,861,867 1,811,162 1,731,012 1,455,608 Long-term debt Affiliate.................. 141,520 25,000 - -(6) 132,836 Other...................... 147,559 165,337 153,000 150,000(6) 289,556 Deferred revenue............. 205,453 184,183 227,528 301,395(6) - Shareholders' equity......... 1,163,659 1,043,419 933,073 826,986(6) 643,185 </TABLE> - --------------- (1) Includes benefits of approximately $22 million, $36 million, $65 million, $43 million and $17 million in 1995, 1994, 1993, 1992 and 1991, respectively, relating to tight gas sand federal income tax credits and $7 million in 1991 associated with the utilization of a net operating loss carryforward. (2) Includes a benefit of approximately $14 million associated with the successful resolution on audit of federal income taxes for prior years. (3) Includes a benefit of approximately $8 million related to reduced estimated state income taxes and certain franchise taxes, a portion of which is treated as income tax under Statement of Financial Accounting Standards ("SFAS") No. 109 - "Accounting for Income Taxes", and a $5 million benefit 21
24 from the reduction of the Company's deferred federal income tax liability resulting from a reevaluation of deferred tax requirements. (4) Includes a benefit of $12 million from the reduction of the Company's deferred federal income tax liability resulting from a reevaluation of deferred tax requirements partially offset by an approximate $7 million predominantly noncash charge primarily to adjust the Company's accumulated deferred federal income tax liability for the increase in the corporate federal income tax rate from 34% to 35%. (5) In May 1994, the Board of Directors declared a two-for-one split of the common stock of the Company to be effected as a nontaxable dividend of one share for each share outstanding. Shares were issued on June 15, 1994 to shareholders of record as of May 31, 1994. All per share amounts presented herein are reflected on a post-split basis. (6) In August 1992, the Company completed the sale of an additional 8.2 million shares of common stock resulting in aggregate net proceeds to the Company of approximately $112 million used primarily to repay long-term debt. In September 1992, the Company completed the sale of a volumetric production payment, resulting in net proceeds of approximately $327 million used to repay long-term debt and for other general corporate purposes. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following review of operations for each of the three years in the period ended December 31, 1995 should be read in conjunction with the consolidated financial statements of the Company and notes thereto beginning with page F-1. RESULTS OF OPERATIONS Net Operating Revenues. Wellhead volume and price statistics for the specified years were as follows: <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, ---------------------------- 1995 1994 1993 ------ ------ ------ <S> <C> <C> <C> Natural Gas Volumes (MMcf per day) North America(1)....................................... 636 686 707 Trinidad............................................... 107 63 2 ------ ------ ------ Total.......................................... 743 749 709 ====== ====== ====== Average Natural Gas Prices ($/Mcf) North America(2)....................................... $ 1.34 $ 1.68 $ 1.92 Trinidad............................................... .97 .93 .89 Composite...................................... 1.29 1.62 1.92 Crude/Condensate Volumes (MBbl per day) North America.......................................... 11.5 10.0 8.8 Trinidad............................................... 5.1 2.5 .1 India.................................................. 2.5 .1 - ------ ------ ------ Total.......................................... 19.1 12.6 8.9 ====== ====== ====== Average Crude/Condensate Prices ($/Bbl) North America.......................................... $17.09 $15.65 $16.39 Trinidad............................................... 16.07 15.50 14.36 India.................................................. 16.81 15.70 - Composite...................................... 16.78 15.62 16.37 </TABLE> - --------------- (1) Includes 48 MMcf per day in 1995 and 1994, and 81 MMcf per day in 1993 delivered under the terms of volumetric production payment and exchange agreements effective October 1, 1992, as amended. (2) Includes an average equivalent wellhead value of $.80 per Mcf in 1995, $1.27 per Mcf in 1994 and $1.57 per Mcf in 1993 for the volumes detailed in note (1), net of transportation costs. 22
25 1995 compared to 1994. During 1995, net operating revenues increased $23 million to $649 million as compared to 1994. Average wellhead natural gas prices for 1995 were down approximately 20% from 1994 reducing net operating revenues by approximately $89 million. In addition, a decrease of 1% in wellhead natural gas volumes from 1994 reduced net operating revenues by approximately $4 million. The Company voluntarily curtailed its United States wellhead natural gas delivered volumes by an average of approximately 105 MMcf per day during 1995 compared to approximately 70 MMcf per day during 1994 due to significantly lower United States wellhead natural gas prices. In addition, the impact of reduced drilling for U.S. natural gas deliverability and the sales of oil and gas reserves and related assets (net of purchases of similar assets) resulted in a reduction of approximately 20 MMcf per day in U.S. delivered volumes for 1995 as compared to 1994. The Company refocused its 1995 drilling activity away from natural gas deliverability and toward natural gas reserve enhancement and crude oil exploitation in the United States in response to the significant decline in United States wellhead natural gas prices, in the latter part of 1994 and early 1995, resulting in the drilling of 189 fewer net natural gas wells and 24 more net oil wells during 1995 as compared to 1994. Wellhead crude oil and condensate average prices increased 7% adding approximately $8 million to net operating revenues compared to 1994. Crude oil and condensate wellhead volumes increased 52% adding approximately $37 million to net operating revenues compared to a year ago primarily reflecting new production on stream offshore India and higher volumes offshore Trinidad and in North America. Gains on sales of reserves and related assets during 1995 increased $9 million to $63 million when compared to 1994 which increase was attributable to the Company's continuing efforts in optimizing the value of its assets. Other marketing activities associated with sales and purchases of natural gas, natural gas price swap transactions, other commodity price hedging of natural gas and crude oil and condensate prices utilizing NYMEX-related commodity market transactions and volumetric production payment-related margins added approximately $105 million to net operating revenues during 1995, an increase of approximately $55 million from 1994. This increase primarily resulted from a gain of $65 million on natural gas commodity price hedging activities utilizing NYMEX-related commodity market transactions in 1995 compared to an $11 million gain during 1994. The average associated costs of natural gas marketing, price swap and volumetric production payment transactions, including, where appropriate, average wellhead value, transportation costs and exchange differentials, decreased $.55 per Mcf. The average price received for these transactions decreased $.50 per Mcf. Related other natural gas marketing volumes decreased 19%. The reduction in other natural gas marketing volumes and prices relates primarily to the exchange of the fuel contracts noted below, lower wellhead market prices and decreased other marketing activities. The reduction in other natural gas marketing volumes, partially offset by the $.05 per Mcf margin increase, resulted in a decrease in net operating revenues of approximately $2 million compared to 1994. The Company realized an $11 million gain in 1995 related to certain natural gas commodity price swap transactions with an Enron Corp. affiliated company that were designated for trading purposes in late 1994. This gain was partially offset by a loss of approximately $3 million related to call option transactions and a loss of $6 million associated with certain NYMEX-related natural gas commodity market transactions that were marked-to-market due to loss of correlation between the NYMEX and the wellhead natural gas prices that such transactions were designated to hedge. (See "Capital Resources and Liquidity - Hedging Transactions.") In March 1995, the Company exchanged existing fuel supply and purchase contracts and related price swap agreements associated with a Texas City cogeneration plant for certain natural gas price swap agreements of equivalent value issued by an Enron Corp. affiliated company. As a result of these transactions, the Company realized a $13 million increase in net operating revenues in 1995 over the amount realized from the exchanged fuel supply and purchase contracts in 1994. (See "Relationship Between the Company and Enron Corp. - Contractual Agreements".) 23
26 1994 compared to 1993. During 1994, net operating revenues increased to $626 million, up $45 million as compared to 1993. Average wellhead natural gas volumes increased approximately 6% compared to 1993 primarily reflecting the effects of development activities in Trinidad and Canada partially offset by voluntary curtailments of production in the United States in 1994. The volume reductions in the United States as a result of voluntary curtailments were more than offset by the new natural gas deliveries from the Kiskadee field offshore Trinidad and increased deliveries in Canada. The increase in wellhead natural gas volumes added $28 million to net operating revenues. Average wellhead natural gas prices were down significantly from 1993 reducing net operating revenues by approximately $83 million. This 16% reduction in average wellhead natural gas prices reflects the overall decline in the United States natural gas markets during the last half of 1994 and increased volumes from Trinidad sold under a long-term contract at a price considerably below North American spot market prices. A 42% increase in wellhead crude oil and condensate volumes over 1993 added $22 million to net operating revenues primarily reflecting development activities in Trinidad and increased production in the United States. A 5% decrease in wellhead crude oil and condensate average prices decreased net operating revenues by approximately $3 million. Gains on sales of selected oil and gas reserves and related assets were $54 million in 1994 as compared to $13 million in 1993. While the quantity of equivalent reserves sold in 1994 was slightly less than 1993, higher average proceeds received per equivalent unit in 1994 as compared to 1993 primarily contributed to the increased gain recognition. In continuing its strategy of fully utilizing its assets in optimizing profitability, cash flow and return on investments, the Company expects to continue the sale of similar properties from time to time. Other marketing activities associated with sales and purchases of natural gas, natural gas and crude oil price swap transactions, other commodity price hedging of natural gas and crude oil prices utilizing NYMEX-related commodity market transactions, and margins relating to the volumetric production payment added $50 million to net operating revenues during 1994. This increase of $42 million from the same period in 1993 primarily results from a gain of $11 million on natural gas commodity price hedging activities utilizing NYMEX-related commodity market transactions in 1994 versus an $18 million loss during 1993 and increased margins associated with other natural gas marketing activities. The average associated costs of natural gas marketing, price swap and volumetric production payment transactions, including, where appropriate, average wellhead value, transportation costs and exchange differentials, decreased $.26 per Mcf. The average price received for these transactions decreased $.19 per Mcf. Related other natural gas marketing volumes increased 10%. The impact of these other marketing activities, a substantial portion of which serve as hedges of commodity price risks for a portion of wellhead deliveries, are more than offset by increases or reductions in revenues associated with market responsive prices for wellhead deliveries. (See Note 2 to Consolidated Financial Statements.) Operating Expenses 1995 as compared to 1994. During 1995, operating expenses of $453 million were $13 million lower than the $466 million incurred in 1994. Lease and well expenses increased approximately $9 million to $69 million primarily due to expanded international operations including the initiation of operations in India in late December 1994 and certain nonrecurring costs incurred related to those operations during 1995. Depreciation, depletion and amortization ("DD&A") expense decreased $26 million to $216 million reflecting a decrease in the average DD&A rate from $.80 per Mcfe in 1994 to $.68 per Mcfe in 1995. The DD&A rate decrease is primarily attributable to an overall decrease of $.09 per Mcfe in certain North America DD&A rates and an increase in the proportion of production from international operations with lower average DD&A rates than incurred in North America operations. General and administrative expenses increased approximately $5 million to $57 million primarily due to expanded international activities. Taxes other than income were $4 million higher in 1995 compared to 1994 primarily due to higher production related taxes associated with new production in India in 1995. 24
27 The Company reduced its total per unit operating costs for lease and well expense, DD&A, general and administrative expense, interest expense, and taxes other than income by $.07 per Mcfe, averaging $1.22 per Mcfe during 1995 compared to $1.29 per Mcfe in 1994. This decrease is primarily attributable to the reduction in the average DD&A rate as noted above partially offset by slight increases in per unit lease and well, general and administrative expenses, and taxes other than income which increase reflects primarily lower volumes associated with the curtailment of natural gas volumes in the U. S. due to the reduction in wellhead natural gas prices. 1994 as compared to 1993. During 1994, total operating expenses of $466 million were approximately $1 million higher than the $465 million incurred in 1993. Lease and well expenses of $60 million were approximately $1 million higher than the prior year primarily due to increased expenses related to new operations offshore Trinidad partially offset by cost reductions in North America. Exploration expenses of $42 million increased $5 million from the previous year primarily due to an increased level of exploration activities. Impairment of unproved oil and gas properties increased $4 million from 1993 primarily due to impairments associated with certain offshore Gulf of Mexico leases. DD&A expense decreased from $250 million in 1993 to $242 million in 1994 reflecting a $.09 per Mcfe decrease in the average DD&A rate including a $.03 per Mcfe reduction in the North American operations DD&A rate. General and administrative expenses increased $6 million to $51 million primarily due to overall higher costs associated with expanded international and domestic operations. Taxes other than income decreased approximately $7 million from 1993 primarily due to lower taxable United States wellhead volumes and prices and reductions included in 1994 related to revisions of certain prior year production taxes. Included in 1994 and 1993 are benefits associated with reductions in state franchise taxes of $4 million and $3 million, respectively. The Company continues to benefit from certain state severance tax exemptions allowed on high cost natural gas volumes. Total per unit operating costs for lease and well expense, DD&A, general and administrative expense, interest expense, and taxes other than income decreased $.14 per Mcfe, averaging $1.29 per Mcfe during 1994 compared to $1.43 per Mcfe for 1993. The decrease was primarily due to per unit reductions in DD&A and taxes other than income as discussed above. Other Income. Other income for 1993 includes $4 million in interest income associated with the investment of funds temporarily surplus to the Company (See Note 4 to Consolidated Financial Statements) and $4 million associated with settlements related to the termination of certain long-term natural gas contracts. Interest Expense Net interest expense in 1995 was up $3 million as compared to 1994 reflecting primarily a higher level of debt outstanding during 1995. (See Note 13 to Consolidated Financial Statements). Net interest expense in 1994 decreased approximately $1 million to $8 million as compared to 1993 primarily due to favorable interest rates on new financing acquired by a subsidiary of the Company in Trinidad and the retirement of higher interest rate debt. The estimated fair value of outstanding interest rate swap agreements at December 31, 1994 was a negative $0.5 million based on termination values obtained from third parties. Income Taxes Income tax provision increased $36 million for 1995 as compared to 1994 primarily resulting from higher income before income taxes, higher foreign income taxed at rates in excess of the U.S. rate and lower benefits associated with tight gas sand federal income tax credits utilized in 1995 as compared to 1994 partially offset by a $14 million benefit associated with the successful resolution on audit of federal income taxes for certain prior years. Income tax provision in 1994 includes a benefit of approximately $36 million associated with tight gas sand federal income tax credit utilization, a benefit of approximately $8 million related to reduced estimated state income taxes and a portion of certain franchise taxes which is treated as income tax under SFAS 25
28 No. 109, and a $5 million benefit from the reduction of the Company's deferred federal income tax liability resulting from a reevaluation of deferred tax requirements. CAPITAL RESOURCES AND LIQUIDITY Cash Flow. The primary sources of cash for the Company during the three-year period ended December 31, 1995 included funds generated from operations, proceeds from the sale of selected oil and gas reserves and related assets and the issuance of new debt. Primary cash outflows included funds used in operations, exploration and development expenditures, dividends, and the repayment of debt. Discretionary cash flow, a frequently used measure of performance for exploration and production companies, is generally derived by adjusting net income to eliminate the effects of depreciation, depletion and amortization, impairment of unproved oil and gas properties, deferred taxes, gains on sales of oil and gas reserves and related assets, certain other miscellaneous non-cash amounts, except for amortization of deferred revenue, and exploration and dry hole expenses. However, based on the continuing practice of the Company of selling selected oil and gas reserves and related assets in furtherance of its strategy of fully utilizing its assets in optimizing profitability, cash flow and return on investments, it believes that net proceeds from these transactions should also be considered as available discretionary cash flow and, accordingly, is presenting those values for all periods shown. The Company generated discretionary cash flow of approximately $525 million in 1995, $514 million in 1994 and $521 million in 1993. The 1995 and 1993 amounts include $11 million and $50 million, respectively, associated with federal income tax refunds resulting from the settlement on audit of federal income taxes paid in certain prior years. Net operating cash flows for each of the years in the three-year period ended December 31, 1995 have been revised to reflect the elimination of the amortization of deferred revenues related to the sale of a volumetric production payment during 1992 as net operating cash flows rather than as investing cash flows as previously reported. Net operating cash flows of $335 million for 1995 decreased approximately $47 million as compared to 1994 primarily reflecting higher accounts receivable arising from international activities, and the settlement in December 1995 of January 1996 NYMEX-related natural gas commodity positions. Net operating cash flows were approximately $383 million in 1994 and $406 million in 1993. Decreased 1994 net operating cash flows were primarily due to the receipt of a refund on settlement of an audit of federal income taxes paid in certain prior years. In accordance with the requirements of SFAS No. 95 - "Statement of Cash Flows", net proceeds from the sale of selected oil and gas reserves and related assets are not included in the determination of net operating cash flows. Sale of Selected Oil and Gas Reserves and Related Assets. During 1995, the Company received proceeds of $102 million from the sale of selected oil and gas reserves and related assets compared to $91 million received in 1994. Taxable gains from the 1995 sales generated federal income taxes of $24 million, leaving net proceeds of $78 million compared to net proceeds after federal income taxes in 1994 of $71 million. The 1994 proceeds of $91 million compared to $42 million received in 1993. While the quantity of equivalent reserves sold in 1994 was slightly less than 1993, higher average proceeds received per equivalent unit of reserves sold in 1994 as compared to 1993 resulted in significantly higher 1994 proceeds. Sale of Volumetric Production Payment. In September 1992, the Company sold a volumetric production payment for $326.8 million to a limited partnership. (See "Business - Marketing - Other Marketing" and Note 5 to Consolidated Financial Statements). Under the terms of the production payment agreements, the Company conveyed a real property interest in approximately 124 Bcfe (136 TBtu) of certain natural gas and other hydrocarbons to the purchaser. Effective October 1, 1993, the agreements were amended providing for the extension of the original term of the volumetric production payment through March 31, 1999 and including a revised schedule of daily quantities of hydrocarbons to be delivered which is approximately one-half of the original schedule. The revised schedule will total approximately 89.1 Bcfe (97.8 TBtu) versus approximately 87.9 Bcfe (96.4 TBtu) remaining to be delivered under the original agreement. Daily quantities of hydrocarbons no longer required to be delivered under the revised schedule during the period from October 1, 1993 through June 30, 1996 are available for sale by the Company. The Company retains responsibility for its working interest share of the cost of operations. In accordance with generally accepted 26
29 accounting principles, the Company accounted for the proceeds received in the transaction as deferred revenue which is being amortized into revenue and income as natural gas and other hydrocarbons are produced and delivered to the purchaser during the term, as revised, of the volumetric production payment thereby matching those revenues with the depreciation of asset values which remained on the balance sheet following the sale and the operating expenses incurred for which the Company retained responsibility. The Company expects the above transaction, as amended, to have minimal impact on future earnings. However, cash made available by the sale of the volumetric production payment has provided considerable financial flexibility for the pursuit of investment alternatives. Exploration and Development Expenditures. The table below sets out components of actual exploration and development expenditures for the years ended December 31, 1995, 1994 and 1993, along with those budgeted for the year 1996. <TABLE> <CAPTION> ACTUAL -------------------- BUDGETED EXPENDITURE CATEGORY 1995 1994 1993 1996 -------------------- ---- ---- ---- --------- (IN MILLIONS) <S> <C> <C> <C> <C> Capital Drilling and Facilities........................... $303 $342 $331 Leasehold Acquisitions............................ 22 52 29 Producing Property Acquisitions................... 127 34 9 Capitalized Interest and Other.................... 12 14 14 ---- ---- ---- Total..................................... 464 442 383 Exploration Expenses................................ 55 59 55 ---- ---- ---- Total............................................... $519 $501 $438 $500-$550 ==== ==== ==== ========= </TABLE> Exploration and development expenditures increased $18 million in 1995 as compared to 1994. Differences in components reflect a significant increase in producing property acquisitions to complement existing United States producing areas. One such property acquisition was for non-cash consideration of $19 million of redeemable preferred stock of a subsidiary of the Company. (See Note 6 to Consolidated Financial Statements). (See "Business - Exploration and Production" for additional information detailing the specific geographic locations of the Company's drilling programs and "Outlook" below for a discussion related to 1996 exploration and development expenditure plans). Exploration and development expenditures increased $63 million, or 14%, in 1994 compared to 1993. The increase primarily reflects the acquisitions of selected properties to complement existing North American producing areas and the addition of new international activities in India. Hedging Transactions. With the objective of enhancing the certainty of future revenues, the Company enters into NYMEX-related commodity price swaps from time to time. Using NYMEX-related commodity price swaps, the Company receives a fixed price for the respective commodity hedged and pays a floating market price, as defined for each transaction, to the counterparty at settlement. In 1995, prices for approximately 35% of the natural gas delivered volumes were hedged using NYMEX-related commodity price swaps. The NYMEX-related natural gas commodity price swaps are priced based on a Henry Hub, Louisiana delivery point. The Henry Hub price has historically had a high degree of correlation with the wellhead price received by the Company which has made such transactions effective natural gas price hedges. During December 1995, there was a loss of correlation between the prices paid under the natural gas commodity price swaps and the wellhead natural gas prices ultimately received for a portion of the Company's hedged natural gas production. This loss of correlation resulted in the recognition of a $6 million pre-tax loss in 1995. With the preliminary indication of a possible change in the overall natural gas market environment at year-end 1995 signaling potentially improving industry conditions, the Company closed substantially all its open NYMEX-related positions regarding natural gas commodity price swaps to participate in this potential upside. While the removal of the hedges has resulted in a deferred net loss of approximately $4 million to be 27
30 recognized during 1996, the Company expects the net reductions to be more than offset by revenue associated with increases in wellhead natural gas prices throughout 1996. Included in the $4 million net loss is a $21 million pre-tax loss related to the first quarter of 1996. Financing. The Company's long-term debt-to-total-capital ratio was 20% and 15% as of December 31, 1995 and 1994, respectively. The Company has entered into an agreement with Enron Corp. pursuant to which the Company may borrow funds from Enron Corp. at a representative market rate of interest on a revolving basis. During 1995, the average of the daily balances of funds borrowed by the Company under the agreement was $15 million and the balance at December 31, 1995 was $142 million. During 1994, there were no funds borrowed by the Company under this agreement. Under a promissory note effective January 1, 1993 at a fixed interest rate of 7%, the Company may advance funds temporarily surplus to the Company to Enron Corp. for investment purposes. Daily outstanding balances of funds advanced to Enron Corp. under the note averaged $154,000 during 1995 and $69 million during 1994 with no balance outstanding at December 31, 1995 and 1994. There was no balance outstanding at December 31, 1995 and $7 million outstanding at December 31, 1994, under a commercial paper program initiated in 1990. Proceeds from the commercial paper program were used to fund current transactions. During 1995, total long-term debt increased $99 million to $289 million as a result of borrowings related to certain international drilling activities and certain producing property acquisitions. (See Note 4 to the Consolidated Financial Statements). The estimated fair value of the Company's long-term debt at December 31, 1995 and 1994 was $294 million and $186 million, respectively, based upon quoted market prices and, where such prices were not available, upon interest rates currently available to the Company at year end. (See Note 13 to the Consolidated Financial Statements). Outlook. Uncertainty continues to exist as to the direction of future North America natural gas price trends, and there is a rather wide divergence in the opinions held by some in the industry. This divergence in opinion is caused by various factors including improvements in the technology used in drilling and completing oil and gas wells that are tending to mitigate the impacts of fewer oil and gas wells being drilled, the deregulation of the natural gas market under Federal Energy Regulatory Commission Order 636 and subsequent related orders, improvements being realized in the availability and utilization of natural gas storage capacity and colder weather experienced in the early portion of the 1995/1996 winter season than in recent years. However, the continually increasing recognition of natural gas as a more environmentally friendly source of energy along with the availability of significant domestically sourced supplies should result in further increases in demand and a supporting/strengthening of the overall natural gas market over time. Being primarily a natural gas producer, the Company is more significantly impacted by changes in natural gas prices than by changes in crude oil and condensate prices. (See "Business - Other Matters - Energy Prices"). Based on the portion of the Company's anticipated natural gas volumes for which prices have not, in effect, been hedged using NYMEX-related commodity market transactions, long-term marketing contracts and the sale of a volumetric production payment, the Company's net income and cash flow sensitivity to changing natural gas prices is approximately $16 million for each $.10 per Mcf change in average wellhead natural gas prices. The Company plans to continue to focus a substantial portion of its development and exploration expenditures in its major producing areas in North America. However, based on the continuing uncertainty associated with North America natural gas prices and the continuing weakness in that market, and as a result of the recent success realized in Trinidad, the opportunities available to the Company in conjunction with the late 1994 signing of agreements in India and the recent winning of a concession in Venezuela, the Company anticipates expending an increasing portion of its available funds in the further development of these opportunities outside North America. In addition, the Company expects to conduct limited exploratory activity in other areas outside of North America in its expenditure plans and will continue to evaluate the potential for involvement in other exploitation type opportunities. (See "Business - Exploration and Production" for additional information detailing the specific geographic locations of the related drilling programs). Early-in-year activity will be managed within an annual expected expenditure level of approximately $500-$550 million for 1996. This early-in-year planning will address the continuing uncertainty with regard to the future of the North America natural gas price environment and will be structured to maintain the flexibility necessary under the Company's continuing strategy of funding exploration, exploitation, development and acquisition activities primarily from available internally generated cash flow. The continuation of expenditures 28
31 in other areas outside of North America in the near term is expected to be primarily for the evaluation of conventional oil and gas exploration and exploitation opportunities in the U.K. North Sea and China, respectively, and coalbed methane recovery prospects in Australia and China. Other prospects in various locations will also attract the expenditure of some funds. Other factors representing positive impacts that are more certain continue to hold good potential for the Company in future periods. While the drilling qualification period for the tight gas sand federal income tax credit expired as of December 31, 1992, the Company continued in 1995, and should continue in the future, to realize significant benefits associated with production from wells drilled during the qualifying period as it will be eligible for the federal income tax credit through the year 2002. However, all other factors remaining equal, the annual benefit, which was approximately $22 million in 1995 and is estimated to be approximately $14 million for 1996, is expected to continue to decline in future periods as production from the qualified wells declines. The drilling qualification period for a certain state severance tax exemption available on qualifying high cost natural gas revenues continues through August 1996 in its current form and in a modified and somewhat reduced form from that point through August 2002. Consequently, new qualifying production will be added prospectively to that presently qualified. (See "Business - Other Matters - Tight Gas Sand Tax Credit (Section 29) and Severance Tax Exemption"). Other natural gas marketing activities are also expected to continue to contribute meaningfully to financial results. The Company completed a fairly significant restructure of its other natural gas marketing portfolio during 1992 with the sale of a volumetric production payment of approximately 124 Bcfe (136 TBtu) for $326.8 million that was subsequently revised in 1993 (See "Business - Marketing - Other Marketing" and Note 5 to Consolidated Financial Statements) and elimination of most delivery obligations under four long-term fixed price marketing contracts. The proceeds from the sale of the volumetric production payment added substantially to the financial flexibility of the Company supporting future development while the combined effect of all elements of the restructuring on net income has not been, and is not expected in the future to be, significant. These factors are expected to contribute significantly to earnings, cash flow, and the ability of the Company to pursue the continuation of an active exploration, exploitation, development and selective acquisition program. The level of exploration and development expenditures may vary in 1996 and will vary in future periods depending on energy market conditions and other related economic factors. Based upon existing economic and market conditions, the Company believes net operating cash flow and available financing alternatives in 1996 will be sufficient to fund its net investing cash requirements for the year. However, the Company has significant flexibility with respect to its financing alternatives and adjustment of its exploration, exploitation, development and acquisition expenditure plans if circumstances warrant. While the Company has certain continuing commitments associated with expenditure plans related to operations in India and anticipates having such in Venezuela, they are not anticipated to be material when considered in relation to the total financial capacity of the Company. Other. The cost of environmental compliance has not been material to the Company. In March 1995, the Financial Accounting Standards Board issued SFAS No. 121 - "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" (the "Standard"). The Standard requires, among other things, that long-lived assets and certain identifiable intangibles to be held and used by an entity be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The Company will adopt the Standard in the first quarter of 1996. The effect of adoption of the Standard is anticipated to result in a non-cash impairment charge of less than $5 million pre-tax. In October 1995, the Financial Accounting Standards Board issued SFAS No. 123 - "Accounting for Stock-Based Compensation". SFAS No. 123 encourages companies to account for stock-based compensation awards based on the fair value of the awards at the date they are granted. The resulting compensation cost would be shown as an expense in the statement of income. Companies can choose not to apply the new accounting method and continue to apply current accounting requirements; however, disclosure will be required as to what net income and earnings per share would have been had the new accounting method been followed. SFAS No. 123 is effective for calendar year 1996. 29
32 INFORMATION REGARDING FORWARD LOOKING STATEMENTS This Annual Report on Form 10-K includes forward looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Although the Company believes that its expectations are based on reasonable assumptions, it can give no assurance that its goals will be achieved. Important factors that could cause actual results to differ materially from those in the forward looking statements herein include, but are not limited to, the extent of the Company's success in acquiring oil and gas properties and in discovering, developing and producing reserves, the timing and extent of changes in commodity prices for natural gas, crude oil and condensate and natural gas liquids, political developments in foreign countries and conditions in the capital markets and equity markets during the periods covered by the forward looking statements. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The information required hereunder is included in this report as set forth in the "Index to Financial Statements" on page F-1. ITEM 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required by this Item regarding directors is set forth in the Proxy Statement under the caption entitled "Election of Directors", and is incorporated herein by reference. See list of "Current Executive Officers of the Registrant" in Part I located elsewhere herein. There are no family relationships among the officers listed, and there are no arrangements or understandings pursuant to which any of them were elected as officers. Officers are appointed or elected annually by the Board of Directors at its first meeting following the Annual Meeting of Shareholders, each to hold office until the corresponding meeting of the Board in the next year or until a successor shall have been elected, appointed or shall have qualified. ITEM 11. EXECUTIVE COMPENSATION The information required by this Item is set forth in the Proxy Statement under the caption "Compensation of Directors and Executive Officers", and is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required by this Item is set forth in the Proxy Statement under the captions "Election of Directors" and "Compensation of Directors and Executive Officers", and is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information required by this Item is set forth in the Proxy Statement under the caption "Certain Transactions", and is incorporated herein by reference. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULE, AND REPORTS ON FORM 8-K (A)(1) AND (2) FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE See "Index to Financial Statements" set forth on page F-1. (A)(3) EXHIBITS See pages E-1 through E-7 for a listing of the exhibits. (B) REPORTS ON FORM 8-K No reports on Form 8-K were filed by the Company during the last quarter of 1995. 30
33 INDEX TO FINANCIAL STATEMENTS ENRON OIL & GAS COMPANY <TABLE> <CAPTION> PAGE ----- <S> <C> Consolidated Financial Statements: Management's Responsibility for Financial Reporting............................... F-2 Reports of Independent Public Accountants......................................... F-3 Consolidated Statements of Income for Each of the Three Years in the Period Ended December 31, 1995.............................................................. F-4 Consolidated Balance Sheets - December 31, 1995 and 1994.......................... F-5 Consolidated Statements of Shareholders' Equity for Each of the Three Years in the Period Ended December 31, 1995................................................. F-6 Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 1995........................................................ F-7 Notes to Consolidated Financial Statements........................................ F-8 Supplemental Information to Consolidated Financial Statements....................... F-23 Financial Statement Schedule: Schedule II - Valuation and Qualifying Accounts and Reserves...................... S-1 Other financial statement schedules have been omitted because they are inapplicable or the information required therein is included elsewhere in the consolidated financial statements or notes thereto. </TABLE> F-1
34 MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING The following consolidated financial statements of Enron Oil & Gas Company and its subsidiaries were prepared by management which is responsible for their integrity, objectivity and fair presentation. The statements have been prepared in conformity with generally accepted accounting principles and, accordingly, include some amounts that are based on the best estimates and judgments of management. Arthur Andersen LLP, independent public accountants, was engaged to audit the consolidated financial statements of Enron Oil & Gas Company and its subsidiaries and issue a report thereon. In the conduct of the audit, Arthur Andersen LLP was given unrestricted access to all financial records and related data including minutes of all meetings of shareholders, the Board of Directors and committees of the Board. Management believes that all representations made to Arthur Andersen LLP during the audit were valid and appropriate. Their audits of the years presented included developing an overall understanding of the Company's accounting systems, procedures and internal controls, and conducting tests and other auditing procedures sufficient to support their opinion on the financial statements. Arthur Andersen LLP was also engaged to examine and report on management's assertion about the effectiveness of the system of internal controls of Enron Oil & Gas Company and its subsidiaries. The reports of Arthur Andersen LLP appear on the following page. The system of internal controls of Enron Oil & Gas Company and its subsidiaries is designed to provide reasonable assurance as to the reliability of financial statements and the protection of assets from unauthorized acquisition, use or disposition. This system includes, but is not limited to, written policies and guidelines including a published code for the conduct of business affairs, conflicts of interest and compliance with laws regarding antitrust, antiboycott and foreign corrupt practices policies, the careful selection and training of qualified personnel, and a documented organizational structure outlining the separation of responsibilities among management representatives and staff groups. The adequacy of financial controls of Enron Oil & Gas Company and its subsidiaries and the accounting principles employed in financial reporting by the Company are under the general oversight of the Audit Committee of the Board of Directors. No member of this committee is an officer or employee of the Company. The independent public accountants have direct access to the Audit Committee and meet with the committee from time to time to discuss accounting, auditing and financial reporting matters. It should be recognized that there are inherent limitations to the effectiveness of any system of internal control, including the possibility of human error and circumvention or override. Accordingly, even an effective system can provide only reasonable assurance with respect to the preparation of reliable financial statements and safeguarding of assets. Furthermore, the effectiveness of an internal control system can change with circumstances. It is management's opinion that, considering the criteria for effective internal control over financial reporting and safeguarding of assets which consists of interrelated components including the control environment, risk assessment process, control activities, information and communication systems, and monitoring, the Company maintained an effective system of internal control as to the reliability of financial statements and the protection of assets against unauthorized acquisition, use or disposition for the year ended December 31, 1995. <TABLE> <S> <C> <C> BEN B. BOYD WALTER C. WILSON FORREST E. HOGLUND Vice President and Senior Vice President and Chairman of the Board, Controller Chief Financial Officer President and Chief Executive Officer </TABLE> Houston, Texas February 16, 1996 F-2
35 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To Enron Oil & Gas Company: We have examined management's assertion that the system of internal control of Enron Oil & Gas Company and its subsidiaries for the year ended December 31, 1995 was adequate to provide reasonable assurance as to the reliability of financial statements and the protection of assets against unauthorized acquisition, use or disposition, included in the accompanying report on Management's Responsibility for Financial Reporting. Our examination was made in accordance with standards established by the American Institute of Certified Public Accountants and, accordingly, included obtaining an understanding of the system of internal control, testing and evaluating the design and operating effectiveness of the system of internal control and such other procedures as we considered necessary in the circumstances. We believe that our examination provides a reasonable basis for our opinion. Because of inherent limitations in any system of internal control, errors or irregularities may occur and not be detected. Also, projections of any evaluation of the system of internal control to future periods are subject to the risk that the system of internal control may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, management's assertion that the system of internal control of Enron Oil & Gas Company and its subsidiaries for the year ended December 31, 1995 was adequate to provide reasonable assurance as to the reliability of financial statements and the protection of assets against unauthorized acquisition, use or disposition is fairly stated in all material respects, based upon current standards of control criteria. ARTHUR ANDERSEN LLP Houston, Texas February 16, 1996 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To Enron Oil & Gas Company: We have audited the accompanying consolidated balance sheets of Enron Oil & Gas Company (a Delaware corporation) and subsidiaries as of December 31, 1995 and 1994, and the related consolidated statements of income, shareholders' equity and cash flows for each of the three years in the period ended December 31, 1995. These financial statements and the schedule referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and the schedule based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Enron Oil & Gas Company and subsidiaries as of December 31, 1995 and 1994, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1995, in conformity with generally accepted accounting principles. Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The financial statement schedule listed in the index to financial statements is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. ARTHUR ANDERSEN LLP Houston, Texas February 16, 1996 F-3
36 ENRON OIL & GAS COMPANY CONSOLIDATED STATEMENTS OF INCOME (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, -------------------------------- 1995 1994 1993 -------- -------- -------- <S> <C> <C> <C> NET OPERATING REVENUES Natural Gas Associated Companies.................................... $229,997 $267,997 $279,921 Trade................................................... 222,118 221,896 225,241 Crude Oil, Condensate and Natural Gas Liquids Associated Companies.................................... 58,233 46,782 38,953 Trade................................................... 66,145 29,556 16,881 Gains on Sales of Reserves and Related Assets.............. 62,821 54,014 13,318 Other...................................................... 9,388 5,578 6,706 -------- -------- -------- Total.............................................. 648,702 625,823 581,020 OPERATING EXPENSES Lease and Well............................................. 69,463 60,384 59,344 Exploration................................................ 42,044 41,811 36,921 Dry Hole................................................... 12,911 17,197 18,355 Impairment of Unproved Oil and Gas Properties.............. 23,715 24,936 20,467 Depreciation, Depletion and Amortization................... 216,047 242,182 249,704 General and Administrative................................. 56,626 51,418 45,274 Taxes Other Than Income.................................... 32,587 28,254 35,396 -------- -------- -------- Total.............................................. 453,393 466,182 465,461 -------- -------- -------- OPERATING INCOME............................................. 195,309 159,641 115,559 OTHER INCOME, NET............................................ 669 2,783 6,635 -------- -------- -------- INCOME BEFORE INTEREST EXPENSE AND TAXES..................... 195,978 162,424 122,194 INTEREST EXPENSE Incurred Affiliate............................................... 1,360 629 - Other................................................... 17,054 13,984 15,378 Capitalized................................................ (6,490) (6,124) (5,457) -------- -------- -------- Net Interest Expense.................................... 11,924 8,489 9,921 -------- -------- -------- INCOME BEFORE INCOME TAXES................................... 184,054 153,935 112,273 INCOME TAX PROVISION (BENEFIT)............................... 41,936 5,937 (25,752) -------- -------- -------- NET INCOME................................................... $142,118 $147,998 $138,025 ======== ======== ======== EARNINGS PER SHARE OF COMMON STOCK........................... $ .89 $ .93 $ .86 ======== ======== ======== AVERAGE NUMBER OF COMMON SHARES.............................. 159,917 159,845 159,966 ======== ======== ======== </TABLE> The accompanying notes are an integral part of these consolidated financial statements. F-4
37 ENRON OIL & GAS COMPANY CONSOLIDATED BALANCE SHEETS (IN THOUSANDS) <TABLE> <CAPTION> AT DECEMBER 31, -------------------------- 1995 1994 ----------- ----------- <S> <C> <C> ASSETS CURRENT ASSETS Cash and Cash Equivalents........................................ $ 23,039 $ 5,810 Accounts Receivable Associated Companies.......................................... 60,777 57,352 Trade......................................................... 107,737 68,781 Inventories...................................................... 11,697 15,731 Other............................................................ 14,582 8,744 ----------- ----------- Total.................................................... 217,832 156,418 OIL AND GAS PROPERTIES (Successful Efforts Method)................. 3,380,924 3,015,435 Less: Accumulated Depreciation, Depletion and Amortization....... (1,499,379) (1,330,624) ----------- ----------- Net Oil and Gas Properties............................... 1,881,545 1,684,811 OTHER ASSETS....................................................... 47,881 20,638 ----------- ----------- TOTAL ASSETS....................................................... $ 2,147,258 $ 1,861,867 =========== =========== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Accounts Payable Associated Companies.......................................... $ 12,902 $ 13,353 Trade......................................................... 120,756 117,791 Accrued Taxes Payable............................................ 19,595 17,631 Dividends Payable................................................ 4,795 4,800 Other............................................................ 11,249 11,026 ----------- ----------- Total.................................................... 169,297 164,601 LONG-TERM DEBT Affiliate........................................................ 141,520 25,000 Other............................................................ 147,559 165,337 OTHER LIABILITIES.................................................. 11,629 10,035 DEFERRED INCOME TAXES.............................................. 308,141 269,292 DEFERRED REVENUE................................................... 205,453 184,183 COMMITMENTS AND CONTINGENCIES (Note 9) SHAREHOLDERS' EQUITY Common Stock, $.01 Par, 160,000,000 Shares Authorized and Issued........................................................ 201,600 201,600 Additional Paid In Capital....................................... 399,379 403,488 Cumulative Foreign Currency Translation Adjustment............... (10,747) (15,298) Retained Earnings................................................ 576,740 453,810 Common Stock Held in Treasury, 150,045 shares at December 31, 1995 and 9,173 shares at December 31, 1994.................... (3,313) (181) ----------- ----------- Total Shareholders' Equity............................... 1,163,659 1,043,419 ----------- ----------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY......................... $ 2,147,258 $ 1,861,867 =========== =========== </TABLE> The accompanying notes are an integral part of these consolidated financial statements. F-5
38 ENRON OIL & GAS COMPANY CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) <TABLE> <CAPTION> CUMULATIVE FOREIGN COMMON ADDITIONAL CURRENCY STOCK TOTAL COMMON PAID IN TRANSLATION RETAINED HELD IN SHAREHOLDERS' STOCK CAPITAL ADJUSTMENT EARNINGS TREASURY EQUITY -------- ---------- ----------- -------- -------- ------------- <S> <C> <C> <C> <C> <C> <C> Balance at December 31, 1992... $200,800 $ 421,747 $ (1,726) $206,165 $ - $ 826,986 Net Income................... - - - 138,025 - 138,025 Dividends Paid/Declared, $.12 Per Share................. - - - (19,195) - (19,195) Translation Adjustment....... - - (5,129) - - (5,129) Treasury Stock Purchased..... - - - - (16,698) (16,698) Treasury Stock Issued Under Stock Option Plans........ - (4,216) - - 13,300 9,084 -------- -------- -------- -------- -------- ---------- Balance at December 31, 1993... 200,800 417,531 (6,855) 324,995 (3,398) 933,073 Net Income................... - - - 147,998 - 147,998 Two-for-One Stock Split...... 800 (800) - - - - Dividends Paid/Declared, $.12 Per Share................. - - - (19,183) - (19,183) Translation Adjustment....... - - (8,443) - - (8,443) Treasury Stock Purchased/ Tendered.................. - - - - (35,960) (35,960) Treasury Stock Issued Under Stock Option Plans........ - (13,243) - - 39,177 25,934 -------- -------- -------- -------- -------- ---------- Balance at December 31, 1994... 201,600 403,488 (15,298) 453,810 (181) 1,043,419 Net Income................... - - - 142,118 - 142,118 Dividends Paid/Declared, $.12 Per Share................. - - - (19,188) - (19,188) Translation Adjustment....... - - 4,551 - - 4,551 Treasury Stock Purchased..... - - - - (17,855) (17,855) Treasury Stock Issued Under Stock Option Plans........ - (4,109) - - 14,438 10,329 Other........................ - - - - 285 285 -------- -------- -------- -------- -------- ---------- Balance at December 31, 1995... $201,600 $ 399,379 $ (10,747) $576,740 $ (3,313) $1,163,659 ======== ======== ======== ======== ======== ========== </TABLE> The accompanying notes are an integral part of these consolidated financial statements. F-6
39 ENRON OIL & GAS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS) <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, -------------------------------- 1995 1994 1993 -------- -------- -------- <S> <C> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES Reconciliation of Net Income to Net Operating Cash Inflows: Net Income................................................. $142,118 $147,998 $138,025 Items Not Requiring (Providing) Cash Depreciation, Depletion and Amortization................... 216,047 242,182 249,704 Impairment of Unproved Oil and Gas Properties.............. 23,715 24,936 20,467 Deferred Income Taxes...................................... 45,173 1,788 25,612 Other, Net................................................. 2,910 (2,735) 1,768 Exploration Expenses....................................... 42,044 41,811 36,921 Dry Hole Expenses.......................................... 12,911 17,197 18,355 Gains On Sales of Reserves and Related Assets.............. (62,821) (54,014) (13,318) Other, Net................................................. 720 4,490 1,242 Changes in Components of Working Capital and Other Liabilities Accounts Receivable..................................... (17,525) (883) (24,586) Inventories............................................. 4,034 (2,163) (4,548) Accounts Payable........................................ 2,514 (25,648) 26,208 Accrued Taxes Payable................................... 1,964 277 7,443 Other Liabilities....................................... 1,544 1,086 772 Other, Net.............................................. (18,791) (1,463) (44,443) Amortization of Deferred Revenue........................... (43,344) (43,345) (73,867) Changes in Components of Working Capital Associated with Investing and Financing Activities...................... (17,858) 31,038 40,042 -------- -------- -------- NET OPERATING CASH INFLOWS................................... 335,355 382,552 405,797 INVESTING CASH FLOWS Additions to Oil and Gas Properties........................ (445,047) (442,078) (383,064) Exploration Expenses....................................... (42,044) (41,811) (36,921) Dry Hole Expenses.......................................... (12,911) (17,197) (18,355) Proceeds from Sales of Reserves and Related Assets (Note 10)..................................................... 102,006 90,515 41,815 Changes in Components of Working Capital Associated with Investing Activities.................................... 18,391 (32,120) (37,256) Other, Net................................................. (11,689) (8,758) (4,905) -------- -------- -------- NET INVESTING CASH OUTFLOWS.................................. (391,294) (451,449) (438,686) FINANCING CASH FLOWS Long-Term Debt Affiliate............................................... 116,520 25,000 - Other................................................... (16,100) (25,300) 33,000 Dividends Paid............................................. (19,193) (19,178) (19,200) Treasury Stock Purchased................................... (17,855) (14,139) (16,698) Proceeds from Sales of Treasury Stock...................... 10,329 4,113 9,084 Other, Net................................................. (533) 1,082 (2,786) -------- -------- -------- NET FINANCING CASH INFLOWS (OUTFLOWS)........................ 73,168 (28,422) 3,400 -------- -------- -------- INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS............. 17,229 (97,319) (29,489) CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR.................................................... 5,810 103,129 132,618 -------- -------- -------- CASH AND CASH EQUIVALENTS AT END OF YEAR..................... $ 23,039 $ 5,810 $103,129 ======== ======== ======== </TABLE> The accompanying notes are an integral part of these consolidated financial statements. F-7
40 ENRON OIL & GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED) 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation. The consolidated financial statements of Enron Oil & Gas Company (the "Company"), 61% of the outstanding common stock of which is owned by Enron Corp., include the accounts of all domestic and foreign subsidiaries. All material intercompany accounts and transactions have been eliminated. Certain reclassifications have been made to the consolidated financial statements for prior years to conform with the current presentation. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. Cash Equivalents. The Company records as cash equivalents all highly liquid short-term investments with maturities of three months or less. (See Note 4 "Long-Term Debt - Financing Arrangements with Enron Corp.") Oil and Gas Operations. The Company accounts for its natural gas and crude oil exploration and production activities under the successful efforts method of accounting. Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. Amortization of any remaining costs of such leases begins at a point prior to the end of the lease term depending upon the length of such term. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive, based on historical experience, is amortized over the average holding period. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred. Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. The costs of all development wells and related equipment used in the production of natural gas and crude oil are capitalized. Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. Estimated future dismantlement, restoration and abandonment costs (classified as long-term liabilities), net of salvage values, are taken into account. Certain other assets are depreciated on a straight-line basis. Inventories, consisting primarily of tubular goods and well equipment held for use in the exploration for, and development and production of natural gas and crude oil reserves, are carried at cost with adjustments made from time to time to recognize changes in condition value. Natural gas revenues are recorded on the entitlement method based on the Company's percentage ownership of current production. Each working interest owner in a well generally has the right to a specific percentage of production, although actual production sold may differ from an owner's ownership percentage. Under entitlement accounting, a receivable is recorded when underproduction occurs and a payable when overproduction occurs. Gains and losses associated with the sale in place of natural gas and crude oil reserves and related assets are classified as net operating revenues in the consolidated statements of income based on the Company's strategy of continuing such sales in maximizing the economic value of its assets. F-8
41 Accounting for Interest and Price Risk Management. The Company engages in price and interest rate risk management activities for primarily non-trading purposes. Such activities consist of transactions to hedge commodity prices associated with the sales of natural gas and crude oil in order to mitigate the risk of market price fluctuations and interest rate swap agreements to effectively convert portions of floating rate debt to a fixed rate basis, thereby reducing the impact of interest rate changes on future income. Changes in the market value of commodity price and interest rate swap transactions entered into as hedges are deferred so that the gain or loss is recognized in the period in which the revenues or expenses associated with the hedged transactions are applicable. In certain situations, the Company has designated portions of and may in the future designate certain commodity price swap transactions or portions thereof as for trading purposes. These transactions are accounted for using the mark-to-market method of accounting. Under this method, unrealized gains or losses resulting from the impact of price movements are recognized as net gains or losses in net operating revenues in the consolidated statements of income. Capitalized Interest Costs. Certain interest costs have been capitalized as a part of the historical cost of unproved oil and gas properties. Interest costs capitalized during each of the three years in the period ended December 31, 1995 are set out in the consolidated statements of income. Income Taxes. The closing on December 13, 1995 of the sale by Enron Corp. of approximately 31 million outstanding shares of the common stock of the Company reduced Enron Corp.'s ownership interest in the Company from 80% to 61% with the result that (i) the Company ceased, effective December 14, 1995, to be included in the consolidated federal income tax return filed by Enron Corp. and (ii) a tax allocation agreement previously in effect between the Company and Enron Corp. was terminated. In addition, effective December 14, 1995, the Company and its subsidiaries and Enron Corp. entered into a new tax agreement pursuant to which, among other things, Enron Corp. has agreed (in exchange for the payment of $13.0 million by the Company) to be liable for, and indemnify the Company against all U.S. federal and state income taxes and certain foreign taxes imposed on the Company for periods prior to the date Enron Corp. reduced its ownership in the Company to less than 80%. The Company does not believe that the cessation of consolidated tax reporting with Enron Corp., the termination of the tax allocation agreement concurrent with deconsolidation and the signing of the new tax agreement with Enron Corp. will have a material adverse effect on its financial condition or results of operations. Prior to December 14, 1995, the Company was included in the consolidated federal income tax return filed by Enron Corp. as the common parent for itself and its subsidiaries and the resulting taxes, including taxes for any state or other taxing jurisdiction that required or permitted a consolidated, combined, or unitary tax return to be filed and in which the Company and/or any of its subsidiaries was included, were apportioned as between the Company and/or any of its subsidiaries and Enron Corp. based on the terms of the tax allocation agreement in effect prior to December 14, 1995. The Company accounts for income taxes under the provisions of Statement of Financial Accounting Standards ("SFAS") No. 109 - "Accounting for Income Taxes". SFAS No. 109 requires the asset and liability approach for accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax bases (See Note 8 "Income Taxes"). Foreign Currency Translation. For subsidiaries whose functional currency is deemed to be other than the U.S. dollar, asset and liability accounts are translated at year-end exchange rates and revenue and expenses are translated at average exchange rates prevailing during the year. Translation adjustments are included as a separate component of shareholders' equity. Earnings Per Share. Earnings per share is computed on the basis of the average number of common shares outstanding during the periods. F-9
42 2. NATURAL GAS AND CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS NET OPERATING REVENUES Natural Gas Net Operating Revenues are comprised of the following: <TABLE> <CAPTION> 1995 1994 1993 -------- -------- -------- <S> <C> <C> <C> Wellhead Natural Gas Revenues Associated Companies(1)(2)....................... $173,864 $279,339 $340,508 Trade............................................ 174,732 162,553 156,301 -------- -------- -------- Total.................................... $348,596 $441,892 $496,809 ======== ======== ======== Other Natural Gas Marketing Activities Gross Revenues from: Associated Companies.......................... $ 78,985 $159,726 $139,576 Trade(3)...................................... 102,904 121,965 135,606 -------- -------- -------- Total.................................... 181,889 281,691 275,182 Associated Costs from: Associated Companies(1)(4)(5)................. 90,121 181,756 182,456 Trade......................................... 56,221 62,513 66,273 -------- -------- -------- Total.................................... 146,342 244,269 248,729 -------- -------- -------- Net...................................... 35,547 37,422 26,453 Commodity Price Transaction Gain (Loss) Trading....................................... 2,688(6) - - Non-Trading(7)................................ 65,284 10,579 (18,100) -------- -------- -------- Total.................................... 67,972 10,579 (18,100) -------- -------- -------- Total.................................... $103,519 $ 48,001 $ 8,353 ======== ======== ======== </TABLE> Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues are comprised of the following: <TABLE> <CAPTION> 1995 1994 1993 -------- -------- -------- <S> <C> <C> <C> Wellhead Crude Oil, Condensate and Natural Gas Liquids Revenues Associated Companies............................. $ 56,681 $ 44,979 $ 38,953 Trade............................................ 66,145 29,556 16,881 -------- -------- -------- Total.................................... $122,826 $ 74,535 $ 55,834 ======== ======== ======== Other Crude Oil and Condensate Marketing Activities Commodity Price Hedging Gain(7).................. $ 1,552 $ 1,803 $ - ======== ======== ======== </TABLE> - --------------- (1) Wellhead Natural Gas Revenues in 1995, 1994 and 1993 include $80,369, $126,783 and $129,504, respectively, associated with deliveries by Enron Oil & Gas Company to Enron Oil & Gas Marketing, Inc., a wholly-owned subsidiary, reflected as a cost in Other Natural Gas Marketing Activities - Associated Costs. (2) Includes $14,022, $22,434 and $46,358 in 1995, 1994 and 1993, respectively, associated with the equivalent wellhead value of volumes delivered under the terms of a volumetric production payment agreement effective October 1, 1992, as amended, net of transportation. (3) Includes $43,344, $43,345 and $73,867 in 1995, 1994 and 1993, respectively, associated with the amortization of deferred revenues under the terms of volumetric production payment and exchange agreements effective October 1, 1992, as amended. (4) Includes the effect of a price swap agreement with a third party which in effect fixed the price of certain purchases through February 1995. F-10
43 (5) Includes $27,549, $33,779 and $65,042 in 1995, 1994 and 1993, respectively, for volumes delivered under volumetric production payment and exchange agreements effective October 1, 1992, as amended, including equivalent wellhead value, any applicable transportation costs and exchange differentials. (6) Includes an $11,255 gain associated with certain NYMEX-related commodity market transactions designated for trading purposes partially offset by a $2,567 loss related to call option transactions and a $6,000 loss associated with certain NYMEX-related natural gas commodity market transactions that were marked-to-market due to loss of correlation between the NYMEX and the wellhead natural gas prices that the positions were designated to hedge. (See Note 13 "Price and Interest Rate Risk Management"). (7) Represents gain or loss associated with commodity price swap transactions primarily with Enron Corp. affiliated companies based on NYMEX-related commodity prices in effect on dates of execution, less customary transaction fees. These transactions serve as price hedges for a portion of wellhead sales. In March 1995, in a series of transactions with Enron Corp. and an affiliate of Enron Corp., the Company exchanged all of its fuel supply and purchase contracts and related price swap agreements associated with a Texas City cogeneration plant (the "Cogen Contracts") for certain natural gas price swap agreements of equivalent value issued by the affiliate that are designated as hedges (the "Swap Agreements"). Such Swap Agreements were closed on March 31, 1995. As a result of the transactions, the Company has been relieved of all performance obligations associated with the Cogen Contracts. Such operating revenues and associated costs through February 28, 1995 were classified as Other Natural Gas Marketing Activities-Gross Revenues and Associated Costs from Associated Companies. The Company will realize net operating revenues classified as Other Natural Gas Marketing Activities-Commodity Price Transaction Gain (Loss), Non-Trading, and receive corresponding cash payments of approximately $91 million during the period extending through December 31, 1999, under the terms of the closed Swap Agreements. The estimated fair value of the Swap Agreements was approximately $81 million at the date the Swap Agreements were received in exchange for the Cogen Contracts. The net effect of this series of transactions has resulted/will result in increases in net operating revenues and cash receipts for the Company during 1995 and 1996 of approximately $13 million and $7 million, respectively, with offsetting decreases in 1998 and 1999 versus those anticipated under the Cogen Contracts. The total cash payments receivable under the terms of the Swap Agreements, approximately $60 million at December 31, 1995, are presented in the accompanying balance sheet as Accounts Receivable - Associated Companies for the $25 million current portion and as Other Assets for the $35 million noncurrent portion. The corresponding total future revenue of approximately $63 million is classified as Deferred Revenue. (See Note 13 "Price and Interest Rate Risk Management"). 3. OTHER ASSETS Other Assets at December 31, 1994 includes an investment in 349,387 shares of Enron Corp. common stock purchased for $10 million, at an average of $28.62 per share from Enron Corp. (the fair market value of such shares on the dates of acquisition). In August 1995, the purchase of an additional 283,946 shares of Enron Corp. common stock for $9.3 million, at an average of $32.71 per share was completed, resulting in a total of 633,333 shares at a total cost of $19.3 million. The Enron Corp. common stock was subsequently exchanged in November 1995 for redeemable preferred stock issued in March 1995 by a subsidiary of the Company. (See Note 6 "Shareholders' Equity"). 4. LONG-TERM DEBT Revolving Credit Agreement. The Company is a party to a Revolving Credit Agreement dated as of March 11, 1994, among the Company and the banks named therein (the "Credit Agreement"). The Credit Agreement provides for aggregate borrowings of up to $100 million, with provisions for increases, at the option of the Company, up to $300 million. Advances under the Credit Agreement bear interest, at the option of the Company, based on a base rate, an adjusted CD rate or a Eurodollar rate. Each advance under the Credit Agreement matures on a date selected by the Company at the time of the advance, but in no event after F-11
44 January 15, 1998. There were no advances outstanding under the Credit Agreement at December 31, 1995 or 1994. Financing Arrangements With Enron Corp. The Company engages in various transactions with Enron Corp. that are characteristic of a consolidated group under common control. Activities of the Company not internally funded from operations have been and may be funded from time to time by advances from Enron Corp. The Company entered into an agreement with Enron Corp., effective October 12, 1989 (as amended effective September 29, 1992) and payable on demand no later than September 29, 1995, under which the Company could borrow funds from Enron Corp. at a representative market rate of interest on a revolving basis. During 1995 and 1994, there were no funds borrowed by the Company under this agreement. Effective as of September 29, 1995, this agreement was replaced with another agreement with Enron Corp. providing for borrowings by the Company of up to $200 million under substantially the same terms as the previous agreement. Advances under this agreement which amounted to $141.5 million at December 31, 1995 are payable on demand on or before December 31, 1998. Such balance was classified as long-term based on the Company's intent and ability to replace such amount with other long-term debt. In January 1996, $105 million was retired using the proceeds from new long-term financings. (See "Long-Term Debt, Other"). In July 1994, the Company prepaid $25 million of loans payable due in April 1995 with proceeds from a promissory note payable to Enron Corp. which note was in the same amount and with essentially the same terms as the loan prepaid. The promissory note was classified as long-term based on the Company's intent and ability to refinance such note upon maturity with other long-term debt. The interest rate swap agreement which effectively fixed the interest rate of the original loan payable at 8.98% through maturity remained in effect for the promissory note payable to Enron Corp. The note was paid in April 1995. The Company also entered into an agreement with Enron Corp., effective October 12, 1989 (as amended effective September 29, 1992), which provides the Company the option of depositing any excess funds that may be available from time to time with Enron Corp. with interest at a representative market rate during the periods the funds were held by Enron Corp. Effective January 1, 1993, the Company executed a promissory note at a fixed interest rate of 7% with Enron Corp. providing for the investment of funds temporarily surplus to the Company from time to time with Enron Corp. Daily outstanding balances of funds advanced to Enron Corp. under this note averaged $154,000 and $68.8 million during 1995 and 1994, respectively. There were no advances outstanding at December 31, 1995 or 1994 under this agreement. Interest income recorded in 1995 and 1994 under the terms of this note totaled $11 thousand and $4.7 million, respectively. Effective as of September 29, 1995, the Company entered into a new credit agreement which replaces the October 12, 1989 credit agreement, as amended, and supplements the promissory note entered into on January 1, 1993. Such new agreement provides the Company the option of depositing any excess funds that may be available from time to time in excess of those advanced under the January 1, 1993 promissory note with Enron Corp. up to a combined total of $200 million under substantially the same terms as included in the October 12, 1989 agreement, as amended, and with a maturity date of December 31, 1998. Long-Term Debt, Other. Long-Term Debt, Other at December 31 consisted of the following: <TABLE> <CAPTION> 1995 1994 -------- -------- <S> <C> <C> Senior Notes...................................... $ 70,000 $ 70,000 Promissory Notes.................................. 71,600 56,000 Commercial Paper.................................. - 6,700 Loan Payable...................................... - 25,000 Capitalized Lease Obligation...................... 5,959 7,637 -------- -------- Total........................................... $147,559 $165,337 ======== ======== </TABLE> The Senior Notes bear interest at 9.1% with principal repayments of $30 million due on February 15, 1996 and $20 million due in 1997 and 1998. The $30 million repayment due on February 15, 1996 is classified as long-term based on the Company's intent and ability to replace such amount upon maturity with other long-term debt. F-12
45 The Promissory Notes represent advances to a subsidiary of the Company. Two advances aggregating $31 million were received in March 1994 under a credit agreement dated as of March 8, 1994 between the subsidiary and a financial institution. One of the advances is in the amount of $16 million, bears interest at a fixed rate of 4.52% and is due in 1998. The other advance is in the amount of $15 million, bears interest at a floating rate that resets quarterly, is equal to 84% of the London Interbank Bid Rate and is due in 1998. Both advances are collateralized with a letter of credit issued by a bank on behalf of the subsidiary and guaranteed by the Company. The advances were used to partially repay a promissory note payable to a bank by the subsidiary. In May 1994 and January 1995, the subsidiary received other advances of $25 million and $15 million, respectively, evidenced by promissory notes, under a credit agreement dated May 27, 1994 between the subsidiary and a financial institution. The credit agreement provides for aggregate borrowings of up to $44 million and is due in 1999. The advances bear interest based on various interest rate options, as defined in the credit agreement, which ranged from 5.27% to 5.57% during 1995. The advances are guaranteed by the Company and were used to partially repay temporary advances from the Company to the subsidiary for qualified development costs. The Commercial Paper outstanding at December 31, 1994 was issued under a commercial paper program the proceeds of which are used to fund current transactions and are classified as long-term based on the Company's intent and ability to replace such obligation with other long-term debt. The Loan Payable was retired in April 1995 using the proceeds from other long-term financings. Interest was at a variable rate based on the London Interbank Offered Rate which had, in effect, been converted to a fixed interest rate of 8.92% through maturity using an interest rate swap agreement in equivalent dollar amounts. The note was classified as long-term based on the Company's intent and ability to replace such loan upon maturity with other long-term debt. Certain of the borrowings described above contain covenants requiring the maintenance of certain financial ratios and limitations on liens, debt issuance and dispositions of assets. In 1991, the Company filed with the Securities and Exchange Commission a registration statement providing for the issuance and sale from time to time of up to $250 million of debt securities to the public. As of December 31, 1995, no debt securities had been issued under this registration statement. Subsequent to year-end, a subsidiary of the Company entered into a Credit Agreement dated as of January 16, 1996 among the subsidiary and the banks named therein and received advances under the agreement, evidenced by promissory notes, aggregating $105 million. Each note matures in January 2001 and bears interest at a floating rate based on the London Interbank Offered Rate for periods selected by the subsidiary. The notes are guaranteed by the Company, the proceeds of which were ultimately used to partially repay advances to the Company by Enron Corp. Fair Value Of Long-Term Debt. At December 31, 1995 and 1994, the Company had $289 million and $190 million, respectively, of long-term debt. The estimated fair value of such debt at December 31, 1995 and 1994 was approximately $294 million and $186 million, respectively. The fair value of long-term debt is the value the Company would have to pay to retire the debt, including any premium or discount to the debtholder for the differential between the stated interest rate and the year-end market rate. The fair value of long-term debt is based upon quoted market prices and, where such quotes were not available, upon interest rates available to the Company at year-end. 5. VOLUMETRIC PRODUCTION PAYMENT In September 1992, the Company sold a volumetric production payment for $326.8 million to a limited partnership. Under the terms of the production payment agreements, the Company conveyed a real property interest of approximately 124 billion cubic feet equivalent ("Bcfe") (136 trillion British thermal units ("TBtu")) of certain natural gas and other hydrocarbons to the purchaser. Effective October 1, 1993, the agreements were amended providing for the extension of the original term of the volumetric production payment through March 31, 1999 and including a revised schedule of daily quantities of hydrocarbons to be delivered which is approximately one-half of the original schedule. The revised schedule will total approximately 89.1 Bcfe (97.8 TBtu) versus approximately 87.9 Bcfe (96.4 TBtu) remaining to be delivered under F-13
46 the original agreement. Daily quantities of hydrocarbons no longer required to be delivered under the revised schedule during the period from October 1, 1993 through June 30, 1996 are available for sale by the Company. The Company retains responsibility for its working interest share of the cost of operations. A portion of the proceeds of the sale was used to repay a portion of the Company's long-term debt, with surplus funds advanced to Enron Corp. under a note agreement which facilitates the deposit of funds temporarily surplus to the Company. The Company accounted for the proceeds received in the transaction as deferred revenue which is being amortized into revenue and income as natural gas and other hydrocarbons are produced and delivered during the term, as revised, of the volumetric production payment agreement. Annual remaining amortization of deferred revenue, based on revised scheduled deliveries under the volumetric production payment agreement, as amended, at December 31, 1995 was as follows: <TABLE> <S> <C> 1996....................................................... $ 43,463 1997....................................................... 43,344 1998....................................................... 43,344 1999....................................................... 10,688 -------- Total............................................ $140,839 ======== </TABLE> 6. SHAREHOLDERS' EQUITY The Board of Directors of the Company approved in December 1992, as amended in September 1994, the purchasing and holding in treasury at any time of up to 500,000 shares of common stock of the Company for, but not limited to, meeting obligations associated with stock option grants to qualified employees pursuant to the Company's stock option plans. (See Note 9 "Commitments and Contingencies - Stock Option Plans"). At December 31, 1995 and 1994, 150,045 shares and 9,173 shares, respectively, were held in treasury under this authorization. On May 3, 1994, the shareholders of the Company approved and the Board of Directors subsequently declared a two-for-one split of the common stock of the Company to be effected as a nontaxable dividend of one share for each share outstanding. Shares were issued on June 15, 1994 to shareholders of record as of May 31,1994. At such time, an amendment to the Restated Certificate of Incorporation of the Company to increase the total number of authorized shares of the common stock of the Company from 80 million to 160 million shares and to change the par value of common stock from no par to $.01 par per share was filed with the Secretary of State of Delaware. All share and per share amounts in the financial statements and supplemental financial information have been restated to consider the effect of the two-for-one stock split. In March 1995, a subsidiary of the Company issued to an unrelated third party 19,000 shares of the subsidiary's non-voting redeemable preferred stock, with a liquidation/redemption value of $1,000 per share and dividends payable semi-annually at an annual rate of $70.00 per share, in exchange for certain oil and gas properties. (See Note 3 "Other Assets"). In February 1996, the Board of Directors authorized submission of a resolution to shareholders for approval at their annual meeting in May 1996 that would amend the Restated Certificate of Incorporation of the Company to increase the total number of authorized shares of the common stock of the Company from 160 million to 320 million shares. Such charter amendment, if adopted, will become effective when the appropriate Certificate of Amendment to the Company's Restated Certificate of Incorporation is filed with the Secretary of State of Delaware. 7. TRANSACTIONS WITH ENRON CORP. AND RELATED PARTIES Natural Gas and Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues. Wellhead Natural Gas and Crude Oil, Condensate and Natural Gas Liquids Revenues and Other Natural Gas and Other Crude Oil and Condensate Marketing Activities include revenues from and associated costs paid to various subsidiaries and affiliates of Enron Corp. pursuant to contracts which, in the opinion of management, are no less favorable than could be obtained from third parties. Other Natural Gas and Other Crude Oil and Condensate Marketing Activities also include certain commodity price swap and NYMEX-related commod- F-14
47 ity transactions with Enron Corp. affiliated companies which, in the opinion of management, are no less favorable than could be obtained from third parties. (See Note 2 "Natural Gas and Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues"). General and Administrative Expenses. The Company is charged by Enron Corp. for all direct costs associated with its operations. Such direct charges, excluding benefit plan charges (See Note 9 "Commitments and Contingencies - Employee Benefit Plans"), totaled $17.2 million, $13.7 million and $11.5 million for the years ended December 31, 1995, 1994 and 1993, respectively. Management believes that these charges are reasonable. Additionally, certain administrative costs not directly charged to any Enron Corp. operations or business segments are allocated to the entities of the consolidated group. Allocation percentages are generally determined utilizing weighted average factors derived from property gross book value, net operating revenues and payroll costs. Effective January 1, 1994, the Company entered into an agreement with Enron Corp. with an initial term of five years through December 1998, which agreement replaced a similar previous agreement, providing for services substantially identical in nature and quality to those services previously provided and for allocated indirect costs incurred in rendering such services up to a maximum of approximately $7 million in 1995 and $6.7 million for 1994. The limit on cost for the allocated indirect services provided by Enron Corp. to the Company will increase in subsequent years for inflation and certain changes in the Company's allocation bases, but such increase will not exceed 7.5% per year. Management believes the indirect allocated charges for the numerous types of support services provided by the corporate staff are reasonable. Approximately $6.8 million, $6.6 million and $7.9 million were charged to the Company for indirect general and administrative expenses for the years ended December 31, 1995, 1994 and 1993, respectively. Financing. See Note 4 "Long-Term Debt - Financing Arrangements with Enron Corp." for a discussion of financing arrangements with Enron Corp. 8. INCOME TAXES The principal components of the Company's net deferred income tax liability at December 31, 1995 and 1994 were as follows: <TABLE> <CAPTION> 1995 1994 -------- -------- <S> <C> <C> Deferred Income Tax Assets Non-Producing Leasehold Costs................................. $ 8,469 $ 7,685 Seismic Costs Capitalized for Tax............................. 5,316 4,683 Other......................................................... 1,460 4,194 -------- -------- Total Deferred Income Tax Assets...................... 15,245 16,562 Deferred Income Tax Liabilities Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization......... 274,219 252,599 Capitalized Interest.......................................... 6,265 5,763 Volumetric Production Payment Book Revenue Over Income for Tax.................................................... 40,591 26,777 Other......................................................... 2,311 715 -------- -------- Total Deferred Income Tax Liabilities................. 323,386 285,854 -------- -------- Net Deferred Income Tax Liability..................... $308,141 $269,292 ======== ======== </TABLE> The components of income (loss) before income taxes were as follows: <TABLE> <CAPTION> 1995 1994 1993 -------- -------- -------- <S> <C> <C> <C> United States....................................... $157,174 $125,510 $117,460 Foreign............................................. 26,880 28,425 (5,187) -------- -------- -------- Total..................................... $184,054 $153,935 $112,273 ======== ======== ======== </TABLE> F-15
48 Total income tax provision (benefit) was as follows: <TABLE> <CAPTION> 1995 1994 1993 -------- -------- -------- <S> <C> <C> <C> Current: Federal.......................................... $ (6,983) $ 113 $(52,555) State............................................ 130 2,745 5 Foreign.......................................... 3,616 1,291 1,186 -------- -------- -------- Total.................................... (3,237) 4,149 (51,364) Deferred: Federal.......................................... 24,733 3,818 20,845 State............................................ 855 (14,414) 4,357 Foreign.......................................... 19,585 12,384 410 -------- -------- -------- Total.................................... 45,173 1,788 25,612 -------- -------- -------- Income Tax Provision (Benefit)..................... $ 41,936 $ 5,937 $(25,752) ======== ======== ======== </TABLE> The differences between taxes computed at the U.S. federal statutory tax rate and the Company's effective rate were as follows: <TABLE> <CAPTION> 1995 1994 1993 -------- -------- -------- <S> <C> <C> <C> Statutory Federal Income Tax Rate.................. 35.00% 35.00% 35.00% State Income Tax, Net of Federal Benefit........... 0.35 (4.93) 2.53 Income Tax Related to Foreign Operations........... 7.21 3.44 3.08 Tight Gas Sand Federal Income Tax Credits.......... (12.19) (23.71) (58.05) Revision of Prior Years' Tax Estimates............. (6.52) (3.25) (10.73) Amended Return Recoveries.......................... (1.09) (2.62) - Federal Tax Rate Increase.......................... - - 5.23 Other.............................................. 0.02 (0.07) - ------ ------ ------ Effective Income Tax Rate................ 22.78% 3.86% (22.94)% ====== ====== ====== </TABLE> Current income tax receivable from (payable to) Enron Corp. at December 31, 1995, 1994 and 1993 amounted to $458, $(506) and $(6,892), respectively. The current taxes payable to the Internal Revenue Service for the short-period of December 14, 1995 through December 31, 1995 are not material. The Company's $2.7 million alternative minimum tax credit carryforward was eliminated when taxes were reallocated between Enron Corp. and the Company after completion of the 1988-1991 Internal Revenue Service audit. The Company's foreign subsidiaries' undistributed earnings of approximately $84 million at December 31, 1995 are considered to be indefinitely invested outside the U.S. and, accordingly, no U.S. federal or state income taxes have been provided thereon. Upon distribution of those earnings in the form of dividends, the Company may be subject to both foreign withholding taxes and U.S. income taxes, net of allowable foreign tax credits. Determination of any potential amount of unrecognized deferred income tax liabilities is not practicable. 9. COMMITMENTS AND CONTINGENCIES Employee Benefit Plans. Employees of the Company are covered by various retirement, stock purchase and other benefit plans of Enron Corp. During each of the years ended December 31, 1995, 1994 and 1993, the Company was charged $6.6 million, $5.1 million and $4.5 million, respectively, for all such benefits, including pension expense totaling $0.8 million, $0.3 million and $0.5 million, respectively, by Enron Corp. As of September 30, 1995, the most recent valuation date, the plan net assets of the Enron Corp. defined benefit plan in which the employees of the Company participate was less than the actuarial present value of projected plan benefit obligations by approximately $19.3 million. The assumed discount rate, rate of return on F-16
49 plan assets and rate of increases in wages used in determining the actuarial present value of projected plan benefits were 7.5%, 10.5% and 4.0%, respectively. The Company also has in effect pension and savings plans related to its Canadian, Trinidadian and Indian subsidiaries. Activity related to these plans is not material relative to the Company's operations. The Company provides certain medical, life insurance and dental benefits to eligible employees who retire under the Enron Corp. Retirement Plan and their eligible surviving spouses. Benefits are provided under the provisions of a contributory defined dollar benefit plan. The Company accrues the cost of these post-retirement benefits over the service lives of the employees expected to be eligible to receive such benefits. The transition obligation existing at January 1, 1993 is being amortized over an average period of 19 years. The accumulated post-retirement benefit obligation ("APBO") existing at December 31, 1995 totaled $131.1 million, of which $114.3 million is applicable to current retirees and current employees eligible to retire. The measurement of the APBO assumes a 7.5% discount rate and a health care cost trend rate of 11.7% in 1995 decreasing to 5% by the year 2006 and beyond. A 1% increase in the health care cost trend rate would have the effect of increasing the APBO and the net periodic expense by approximately $8.8 million and $0.6 million, respectively. The Company does not currently intend to prefund its obligations under its post-retirement welfare benefit plans. Stock Option Plans. The Company has various stock option plans ("the Plans") under which employees of the Company and its subsidiaries and non-employee members of the Board of Directors have been or may be granted rights to purchase shares of common stock of the Company generally at a price not less than the market price of the stock at the date of grant. Options granted under the Plans vest over a period of time based on the nature of the grants and as defined in the individual grant agreements. The following table sets forth the transactions for the Plans for the years ended December 31: <TABLE> <CAPTION> NUMBER OF STOCK OPTIONS ------------------------------------- 1995 1994 1993 -------- --------- -------- <S> <C> <C> <C> Outstanding at January 1....................... 7,214,555 4,124,800 3,908,050 Granted...................................... 1,650,030(1) 5,128,095(1) 920,600 Exercised.................................... (621,927) (1,967,920) (671,850) Forfeited.................................... (223,893) (70,420) (32,000) --------- --------- --------- Outstanding at December 31 (Grant Prices of $9.25 - $24.38 per Share).................... 8,018,765 7,214,555 4,124,800 ========= ========= ========= Available for Grant at December 31............. 3,792,038 3,218,175 1,075,850 ========= ========= ========= </TABLE> - --------------- (1) Includes 170,985 and 1,920,275 options granted on December 29, 1995 and December 30, 1994, respectively, under all employee stock option grants. At December 31, 1995, 4,716,320 options outstanding were vested. Of the remaining unvested options, 1,054,292, 895,977, 751,227, 566,752 and 34,197 vest in the years 1996, 1997, 1998, 1999 and 2000, respectively. During 1995, 1994 and 1993, the Company purchased or was tendered 762,799, 1,817,093 and 831,850 of its common shares, respectively, and delivered such shares upon the exercise of stock options, except for shares held in treasury at December 31, 1995, 1994 and 1993 as set out below. The difference between the cost of the treasury shares and the exercise price of the options, net of federal income tax benefit of $2.2 million, $7.2 million and $2.8 million for the years 1995, 1994 and 1993, respectively, is reflected as an adjustment to Additional Paid In Capital. In October 1993, as amended in September 1994, the Company commenced a stock repurchase program authorized by the Board of Directors to facilitate the availability of treasury shares of common stock for, but not limited to, the settlement of employee stock option exercises pursuant to the Plans. At December 31, 1995 and 1994, 150,045 and 9,173 shares, respectively, were held in treasury under this authorization. (See Note 6 "Shareholders' Equity"). F-17
50 In October 1995, the Financial Accounting Standards Board issued SFAS No. 123 - "Accounting for Stock-Based Compensation". SFAS No. 123 encourages companies to account for stock-based compensation awards based on the fair value of the awards at the date they are granted. The resulting compensation cost would be shown as an expense in the statement of income. Companies can choose not to apply the new accounting method and continue to apply current accounting requirements; however, disclosure will be required as to what net income and earnings per share would have been had the new accounting method been followed. SFAS No. 123 is effective for calendar year 1996. Letters Of Credit. At December 31, 1995 and 1994, the Company had letters of credit outstanding totaling approximately $32 million issued in connection with a loan between one of the Company's subsidiaries and a trust. Contingencies. There are various suits and claims against the Company having arisen in the ordinary course of business. However, management does not believe these suits and claims will individually or in the aggregate have a material adverse effect on the Company's financial condition or results of operations. On November 19, 1992, TransAmerican Natural Gas Corporation ("TransAmerican") filed a petition against the Company alleging breach of contract, tortious interference with contract, misappropriation of trade secrets and violation of state antitrust laws. The petition, as amended, sought actual damages of at least $100 million plus exemplary damages of $300 million. The Company filed counterclaims against TransAmerican and a third-party claim against its sole shareholder, John R. Stanley, alleging fraud, negligent misrepresentation and breach of state antitrust laws. On October 16, 1995, the Company, TransAmerican and Stanley entered into an agreement which resolved all claims. The settlement terms did not have a materially adverse effect on the Company's financial condition or results of operations. The suit was dismissed with prejudice as to all parties by order entered in November 1995. The Company has been named as a potentially responsible party in certain Comprehensive Environmental Response Compensation and Liability Act proceedings. However, management does not believe that any potential assessments resulting from such proceedings will individually or in the aggregate have a materially adverse effect on the financial condition or results of operations of the Company. 10. CASH FLOW INFORMATION Gains on sales of certain oil and gas reserves and related assets in the amount of $62.8 million, $54.0 million and $13.3 million for the years ended December 31, 1995, 1994 and 1993, respectively, are required by current accounting guidelines to be removed from net income in connection with determining net operating cash inflows while the related proceeds are required to be classified as investing cash flows. The Company believes that proceeds from the sales of reserves and related assets should be considered in analyzing the elements of operating cash flows. The current federal income tax impact of these sales transactions was calculated by the Company to be $24.4 million, $19.8 million and $8.2 million for the years ended December 31, 1995, 1994 and 1993, respectively, which entered into the overall calculation of current federal income tax. The Company believes that this federal income tax impact should also be considered in analyzing the elements of the cash flow statement. The consolidated statements of cash flows for 1994 and 1993 have been revised to reflect the elimination of the non-cash amortization of deferred revenue from net operating cash flows rather than investing cash flows as previously reported. Non-cash investing and financing activities for 1995 include the issuance by a subsidiary of the Company of redeemable preferred stock with a liquidation/redemption value of $19 million in exchange for certain oil and gas properties (See Note 6 "Shareholders' Equity"). An approximate $7 million step-up in property basis was made relating to deferred tax liabilities associated with the difference between the tax and book bases of acquired properties as required by SFAS No. 109 for a nontaxable business combination. F-18
51 Cash paid for interest and paid (received) for income taxes was as follows for the years ended December 31: <TABLE> <CAPTION> 1995 1994 1993 ------- ------- -------- <S> <C> <C> <C> Interest (net of amount capitalized).................... $11,307 $10,436 $ 10,517 Income taxes............................................ 10,140 1,352 (65,543) </TABLE> Included in 1995 income taxes paid is $13 million paid to Enron Corp. for the indemnification of any future liability associated with all federal and state income taxes and certain foreign taxes imposed on the Company for periods prior to the date Enron Corp. reduced its ownership in the Company from 80% to 61%. 11. BUSINESS SEGMENT INFORMATION The Company's operations are all natural gas and crude oil exploration and production related. Accordingly, such operations are classified as one business segment. Financial information by geographic area is presented below for the years ended December 31, or at December 31: <TABLE> <CAPTION> 1995 1994 1993 ---------- ---------- ---------- <S> <C> <C> <C> Gross Operating Revenues United States.............................. $ 582,993 $ 656,546 $ 653,929 Foreign.................................... 131,682 86,763 46,316 ---------- ---------- ---------- Total(1).............................. $ 714,675 $ 743,309 $ 700,245 ========== ========== ========== Operating Income (Loss) United States.............................. $ 162,652 $ 138,001 $ 126,410 Foreign.................................... 32,657 21,640 (10,851) ---------- ---------- ---------- Total................................. $ 195,309 $ 159,641 $ 115,559 ========== ========== ========== Identifiable Assets United States.............................. $1,693,293 $1,505,926 $1,564,330 Foreign.................................... 453,965 355,941 246,832 ---------- ---------- ---------- Total................................. $2,147,258 $1,861,867 $1,811,162 ========== ========== ========== </TABLE> - --------------- (1) Not deducted are natural gas associated costs of $65,973, $117,486 and $119,225 in 1995, 1994 and 1993, respectively. 12. OTHER INCOME, NET Other income, net consisted of the following for the years ended December 31: <TABLE> <CAPTION> 1995 1994 1993 ---------- ---------- ---------- <S> <C> <C> <C> Interest Income................................. $ 556 $ 4,990 $ 5,789 Reserve Accruals................................ 379 (3,143) (2,520) Contract Settlements............................ - - 4,248 Other, Net...................................... (266) 936 (882) ---------- ---------- ---------- Total................................. $ 669 $ 2,783 $ 6,635 ========== ========== ========== </TABLE> 13. PRICE AND INTEREST RATE RISK MANAGEMENT Periodically, the Company enters into certain trading and non-trading activities including NYMEX-related commodity market transactions and other contracts. The non-trading portions of these activities have been designated to hedge the impact of market price fluctuations on anticipated commodity delivery volumes or other contractual commitments. F-19
52 Trading Activities. The Company realized an $11.3 million gain in 1995 related to certain natural gas commodity price swap transactions with an Enron Corp. affiliated company that were designated for trading purposes in December 1994 and closed in the first quarter of 1995. In 1995, the Company sold a call option with a notional volume of 50 billion British thermal units ("BBtu") per day at a strike price of $2.10 per million British thermal units ("MMBtu") for each month in the period January 1996 through December 1996. At December 31, 1995 the approximate market value of the outstanding call option was $1.8 million. The Company recognized a $2.6 million loss in 1995 related to this call option. In the first quarter of 1996, the Company purchased a call option with a notional volume of 50 BBtu per day at a strike price of $2.10 per MMBtu for the period February 1996 through December 1996 for $3.0 million to offset the call option discussed above. The purchase resulted in a $1.2 million loss to be recognized in the first quarter of 1996. There were no trading gains or losses in 1993 or 1994. The following table summarizes the estimated fair value of financial instruments held for trading purposes: <TABLE> <CAPTION> 1995 -------------------------- CARRYING AVERAGE AMOUNT FAIR VALUE(1) -------- ------------- (IN MILLIONS) <S> <C> <C> Options Written............................................. $ (1.8) $ (.3) NYMEX-related Commodity Market Positions.................... - .4 </TABLE> - --------------- (1) Estimated fair values have been determined by using available market data and valuation methodologies. Judgment is necessarily required in interpreting market data and the use of different market assumptions or estimation methodologies may affect the estimated fair value amounts. Interest Rate Swap Agreements. At December 31, 1995, there were no interest rate swap agreements outstanding. At December 31, 1994, the Company had outstanding interest rate swap agreements with notional principal amounts of $50 million which terminated in April 1995. The interest rate swap agreements were entered into to hedge certain floating rate obligations and effectively fix the interest rate on the notional amount of debt at 8.98% and 8.92%. The estimated fair value of the outstanding swap agreements at December 31, 1994 was a negative $0.5 million. The fair value of interest rate swap agreements is based upon termination values obtained from third parties. Foreign Currency Contracts. The Company enters into foreign currency contracts from time to time to hedge specific currency exposure from commercial transactions. At December 31, 1995 and 1994, there were no foreign currency contracts outstanding. Subsequent to year-end, a subsidiary of the Company and the Company entered into offsetting foreign currency and interest rate swap agreements with an aggregate notional principal amount of $210 million. Such swap agreements are scheduled to terminate in 2001. Hedging Transactions. With the objective of enhancing the certainty of future revenues, the Company enters into NYMEX-related commodity price swaps from time to time. Using NYMEX-related commodity price swaps, the Company receives a fixed price for the respective commodity hedged and pays a floating market price, as defined for each transaction, to the counterparty at settlement. The NYMEX-related natural gas commodity price swaps are priced based on a Henry Hub, Louisiana delivery point. The Henry Hub price has historically had a high degree of correlation with the wellhead price received by the Company which has made such transactions effective natural gas price hedges. During December 1995, there was a loss of correlation between the prices paid under the natural gas commodity price swaps and the wellhead natural gas prices ultimately received for a portion of the Company's hedged natural gas production. This loss of correlation resulted in the recognition of a $6 million loss in 1995. F-20
53 At December 31, 1995, the Company had outstanding positions covering notional volumes of approximately 169 TBtu of natural gas for 1996 and 11 TBtu of natural gas for each of the years 1997 through 2005 and approximately 3.6 million barrels ("MMBbl"), 2.8 MMBbl, 2.8 MMBbl, 2.2 MMBbl, and .9 MMBbl of crude oil and condensate for the years 1996 through 2000, respectively. The fair value of the positions was a positive $16.0 million at December 31, 1995. The Company closed substantially all of its NYMEX-related natural gas commodity price swaps by entering into offsetting positions during the first quarter of 1996 resulting in a deferred net pre-tax loss of approximately $4 million that will be recognized during 1996, including a $21 million loss related to the first quarter of 1996. In 1995, the Company also issued options exercisable at one time by the counterparty on or before December 17, 1996, covering notional volumes of approximately 73 TBtu of natural gas for each of the years 1997 and 1998. The fair value of the option was a positive $8.3 million at December 31, 1995. Such options were embedded in NYMEX-related natural gas commodity price swaps designated as hedges. The following table summarizes the estimated fair value of financial instruments and related transactions for non-trading activities at December 31, 1995 and 1994: <TABLE> <CAPTION> 1995 1994 ------------------------- ------------------------- CARRYING ESTIMATED CARRYING ESTIMATED AMOUNT FAIR VALUE(1) AMOUNT FAIR VALUE(1) -------- ------------- -------- ------------- (IN MILLIONS) (IN MILLIONS) <S> <C> <C> <C> <C> Long-Term Debt(2)........................ $289.1 $ 294.0 $190.3 $ 185.7 Energy Commodity Price Swaps(3)(4)....... - - - (103.7) Related Fixed Price Sales Contract(3)(4)......................... - - - 170.8 Swap Agreements(4)....................... 62.8 58.8 - - NYMEX-Related Commodity Market Positions.............................. (5.1) 10.9 - 30.7 </TABLE> - --------------- (1) Estimated fair values have been determined by using available market data and valuation methodologies. Judgment is necessarily required in interpreting market data and the use of different market assumptions or estimation methodologies may affect the estimated fair value amounts. (2) See Note 4 "Long-Term Debt." (3) The fair value of the Energy Commodity Price Swaps should be considered with the fair value of the Related Fixed Price Sales Contract in determining the overall market risk of these related business transactions. (4) See Note 2 "Natural Gas and Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues". Credit Risk. While notional contract amounts are used to express the magnitude of price and interest rate swap agreements, the amounts potentially subject to credit risk, in the event of nonperformance by the other parties, are substantially smaller. The Company does not anticipate nonperformance by the other parties. 14. CONCENTRATION OF CREDIT RISK Substantially all of the Company's accounts receivable at December 31, 1995 and 1994 result from crude oil and natural gas sales and/or joint interest billings to affiliate and third party companies in the oil and gas industry. This concentration of customers and joint interest owners may impact the Company's overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. In determining whether or not to require collateral from a customer or joint interest owner, the Company analyzes the entity's net worth, cash flows, earnings, and credit ratings. Receivables are generally not collateralized. Historical credit losses incurred on receivables by the Company have been immaterial. F-21
54 15. OTHER In March 1995, the Financial Accounting Standards Board issued SFAS No. 121 - "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" (the "Standard"). The Standard requires, among other things, that long-lived assets and certain identifiable intangibles to be held and used by an entity be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The Company will adopt the Standard in the first quarter of 1996. The effect of adoption of the Standard is anticipated to result in a non-cash impairment charge of less than $5 million pre-tax. F-22
55 ENRON OIL & GAS COMPANY SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (IN THOUSANDS EXCEPT PER SHARE AMOUNTS UNLESS OTHERWISE INDICATED) (UNAUDITED EXCEPT FOR RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES) OIL AND GAS PRODUCING ACTIVITIES The following disclosures are made in accordance with SFAS No. 69 - "Disclosures about Oil and Gas Producing Activities": Oil and Gas Reserves. Users of this information should be aware that the process of estimating quantities of "proved" and "proved developed" crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. Proved reserves represent estimated quantities of crude oil, condensate, natural gas and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. Proved developed reserves are proved reserves expected to be recovered, through wells and equipment in place and under operating methods being utilized at the time the estimates were made. Canadian provincial royalties are determined based on a graduated percentage scale which varies with prices and production volumes. Canadian reserves, as presented on a net basis, assume prices and royalty rates in existence at the time the estimates were made, and the Company's estimate of future production volumes. Future fluctuations in prices, production rates, or changes in political or regulatory environments could cause the Company's share of future production from Canadian reserves to be materially different from that presented. Estimates of proved and proved developed reserves at December 31, 1995, 1994 and 1993 were based on studies performed by the engineering staff of the Company for reserves in the United States, Canada, Trinidad and India. Opinions by DeGolyer and MacNaughton, independent petroleum consultants, for the years ended December 31, 1995, 1994 and 1993 covering producing areas containing 73%, 59% and 65%, respectively, of proved reserves of the Company on a net-equivalent-cubic-feet-of-gas basis, indicate that the estimates of proved reserves prepared by the Company's engineering staff for the properties reviewed by DeGolyer and MacNaughton, when compared in total on a net-equivalent-cubic-feet-of-gas basis, do not differ materially from the estimates prepared by DeGolyer and MacNaughton. Such estimates by DeGolyer and MacNaughton in the aggregate varied by not more than 5% from those prepared by the engineering staff of the Company. All reports by DeGolyer and MacNaughton were developed utilizing geological and engineering data provided by the Company. The presentation of estimated proved reserves has been restated to exclude, for each of the years presented, those quantities attributable to future deliveries required under a volumetric production payment. In order to calculate such amounts, the Company has assumed that deliveries under the volumetric production payment are made as scheduled at expected British thermal unit factors, and that delivery commitments are satisfied through delivery, as scheduled, of the related volumes. The Company has also presented, as additional information, proved reserves including quantities attributable to future deliveries required under the volumetric production payment. The Company believes that this information is informative to readers of its financial statements as the related oil and gas properties costs and deferred revenue are included in the Company's balance sheets for each of the years presented. This additional information is not required to be presented in accordance with SFAS No. 69; however, the Company believes this additional information is useful in assessing its reserve and financial position on a comprehensive basis. No major discovery or other favorable or adverse event subsequent to December 31, 1995 is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date. F-23
56 The following table sets forth the Company's net proved and proved developed reserves at December 31 for each of the four years in the period ended December 31, 1995, and the changes in the net proved reserves for each of the three years in the period then ended as estimated by the engineering staff of the Company. NET PROVED AND PROVED DEVELOPED RESERVE SUMMARY <TABLE> <CAPTION> UNITED STATES CANADA TRINIDAD INDIA TOTAL ------------- ------ -------- ------ ------- <S> <C> <C> <C> <C> <C> Natural Gas (Bcf)(1) Net proved reserves at December 31, 1992.................................. 1,326.1 232.5 - - 1,558.6 Revisions of previous estimates....... (31.3) 11.0 - - (20.3) Purchases in place.................... 9.2 2.6 - - 11.8 Extensions, discoveries and other additions........................... 234.9 47.7 101.3 - 383.9 Sales in place........................ (13.7) (1.5) - - (15.2) Production............................ (212.0) (21.3) (.8) - (234.1) ------- ------ ------ ------ ------- Net proved reserves at December 31, 1993.................................. 1,313.2 271.0 100.5 - 1,684.7 Additional disclosures: Volumes attributable to volumetric production payment.................. 87.5 - - - 87.5 ------- ------ ------ ------ ------- Net proved reserves at December 31, 1993, including volumes attributable to volumetric production payment......... 1,400.7 271.0 100.5 - 1,772.2 ======= ====== ====== ====== ======= Net proved reserves at December 31, 1993.................................. 1,313.2 271.0 100.5 - 1,684.7 Revisions of previous estimates....... (17.1) (6.5) 15.0 - (8.6) Purchases in place.................... 18.8 9.2 - 29.3 57.3 Extensions, discoveries and other additions........................... 233.8 50.2 113.9 - 397.9 Sales in place........................ (29.3) (1.0) - - (30.3) Production............................ (212.0) (26.3) (23.2) - (261.5) ------- ------ ------ ------ ------- Net proved reserves at December 31, 1994.................................. 1,307.4 296.6 206.2 29.3 1,839.5 Additional disclosures: Volumes attributable to volumetric production payment.................. 70.9 - - - 70.9 ------- ------ ------ ------ ------- Net proved reserves at December 31, 1994, including volumes attributable to volumetric production payment......... 1,378.3 296.6 206.2 29.3 1,910.4 ======= ====== ====== ====== ======= Net proved reserves at December 31, 1994.................................. 1,307.4 296.6 206.2 29.3 1,839.5 Revisions of previous estimates....... 10.1 (8.1) 17.5 (29.3) (9.8) Purchases in place.................... 174.8 - - - 174.8 Extensions, discoveries and other additions........................... 1,391.6(2) 54.8 60.8 75.0 1,582.2 Sales in place........................ (38.1) (1.7) - - (39.8) Production............................ (191.7) (27.7) (39.0) - (258.4) ------- ------ ------ ------ ------- Net proved reserves at December 31, 1995.................................. 2,654.1(2) 313.9 245.5 75.0 3,288.5 Additional disclosures: Volumes attributable to volumetric production payment.................. 54.2 - - - 54.2 ------- ------ ------ ------ ------- Net proved reserves at December 31, 1995, including volumes attributable to volumetric production payment......... 2,708.3(2) 313.9 245.5 75.0 3,342.7 ======= ====== ====== ====== ======= </TABLE> (Table continued on following page) F-24
57 <TABLE> <CAPTION> UNITED STATES CANADA TRINIDAD INDIA TOTAL ------------- ------ -------- ------ ------- <S> <C> <C> <C> <C> <C> Liquids (MBbl)(3)(4) Net proved reserves at December 31, 1992.................................. 13,865 5,358 - - 19,223 Revisions of previous estimates....... 1,490 (536) - - 954 Purchases in place.................... 15 489 - - 504 Extensions, discoveries and other additions........................... 3,552 1,115 2,251 - 6,918 Sales in place........................ (3,230) (23) - - (3,253) Production............................ (2,520) (932) (33) - (3,485) ------------- ------ -------- ------ ------- Net proved reserves at December 31, 1993.................................. 13,172 5,471 2,218 - 20,861 Revisions of previous estimates....... 2,179 (177) 455 - 2,457 Purchases in place.................... 358 - - 7,617 7,975 Extensions, discoveries and other additions........................... 5,332 2,848 2,687 - 10,867 Sales in place........................ (257) - - - (257) Production............................ (2,997) (905) (931) (32) (4,865) ------------- ------ -------- ------ ------- Net proved reserves at December 31, 1994.................................. 17,787 7,237 4,429 7,585 37,038 Revisions of previous estimates....... (413) (351) 396 4,874 4,506 Purchases in place.................... 4,264 - - - 4,264 Extensions, discoveries and other additions........................... 8,703 729 3,896 - 13,328 Sales in place........................ (1,241) (9) - - (1,250) Production............................ (3,701) (1,021) (1,851) (917) (7,490) ------------- ------ -------- ------ ------- Net proved reserves at December 31, 1995.................................. 25,399 6,585 6,870 11,542 50,396 ========== ====== ====== ====== ====== Net proved developed reserves at Natural Gas (Bcf) December 31, 1992................... 1,054.1 194.4 - - 1,248.5 December 31, 1993................... 1,079.8 250.6 71.4 - 1,401.8 December 31, 1994................... 1,128.2 288.3 206.2 - 1,622.7 December 31, 1995................... 1,218.1 310.1 233.9 - 1,762.1 Liquids (MBbl)(4) December 31, 1992................... 12,762 5,329 - - 18,091 December 31, 1993................... 11,165 5,409 1,591 - 18,165 December 31, 1994................... 16,770 7,073 4,429 7,585 35,857 December 31, 1995................... 19,977 6,505 5,607 11,542 43,631 Net proved developed reserves, including amounts attributable to volumetric production payment at Natural Gas (Bcf) December 31, 1992................... 1,168.4 194.4 - - 1,362.8 December 31, 1993................... 1,167.3 250.6 71.4 - 1,489.3 December 31, 1994................... 1,199.1 288.3 206.2 - 1,693.6 December 31, 1995................... 1,272.3 310.1 233.9 - 1,816.3 </TABLE> - --------------- (1) Billion cubic feet. (2) Includes 1,180.0 Bcf of proved undeveloped methane reserves contained, along with high concentrations of carbon dioxide and other gases in deep Wyoming Paleozoic formations in the Big Piney area of Wyoming. The Company is actively pursuing the consummation of a market or markets from several different potential sources to facilitate realizing the value of these reserves. (3) Thousand barrels. (4) Includes crude oil, condensate and natural gas liquids. F-25
58 Capitalized Costs Relating to Oil and Gas Producing Activities. The following table sets forth the capitalized costs relating to the Company's natural gas and crude oil producing activities at December 31, 1995 and 1994: <TABLE> <CAPTION> 1995 1994 ----------- ----------- <S> <C> <C> Proved Properties......................................... $ 3,253,593 $ 2,889,242 Unproved Properties....................................... 127,331 126,193 ----------- ----------- Total........................................... 3,380,924 3,015,435 Accumulated depreciation, depletion and amortization...... (1,499,379) (1,330,624) ----------- ----------- Net capitalized costs..................................... $ 1,881,545 $ 1,684,811 =========== =========== </TABLE> Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities. The acquisition, exploration and development costs disclosed in the following tables are in accordance with definitions in SFAS No. 19 - "Financial Accounting and Reporting by Oil and Gas Producing Companies". Acquisition costs include costs incurred to purchase, lease, or otherwise acquire property. Exploration costs include exploration expenses, additions to exploration wells in progress, and depreciation of support equipment used in exploration activities. Development costs include additions to production facilities and equipment, additions to development wells in progress and related facilities, and depreciation of support equipment and related facilities used in development activities. F-26
59 The following tables set forth costs incurred related to the Company's oil and gas activities for the years ended December 31: <TABLE> <CAPTION> FOREIGN -------------------------------------- UNITED STATES CANADA TRINIDAD INDIA OTHER TOTAL ------------- ------- -------- ------- ------- -------- <S> <C> <C> <C> <C> <C> <C> 1995 Acquisition Costs of Properties Unproved.................... $ 16,196 $ 4,645 $ - $ - $ 1,482 $ 22,323 Proved...................... 122,369 116 - 5,000 - 127,485 --------- ------- -------- ------- ------- -------- Total............... 138,565 4,761 - 5,000 1,482 149,808 Exploration Costs............. 47,463 7,197 374 (98) 17,948 72,884 Development Costs............. 217,674 28,611 32,692 16,756 577 296,310 --------- ------- -------- ------- ------- -------- Total............... $ 403,702 $40,569 $ 33,066 $21,658 $20,007 $519,002 ========= ======= ======== ======= ======= ======== 1994 Acquisition Costs of Properties Unproved.................... $ 45,776 $ 6,618 $ - $ - $ (17) $ 52,377 Proved...................... 17,367 4,523 - 12,300 - 34,190 --------- ------- -------- ------- ------- -------- Total............... 63,143 11,141 - 12,300 (17) 86,567 Exploration Costs............. 70,669 8,210 850 2,302 11,242 93,273 Development Costs............. 223,241 35,896 60,778 767 564 321,246 --------- ------- -------- ------- ------- -------- Total............... $ 357,053 $55,247 $ 61,628 $15,369 $11,789 $501,086 ========= ======= ======== ======= ======= ======== 1993 Acquisition Costs of Properties Unproved.................... $ 23,686 $ 4,556 $ - $ - $ 887 $ 29,129 Proved...................... 6,625 2,598 - - - 9,223 --------- ------- -------- ------- ------- -------- Total............... 30,311 7,154 - - 887 38,352 Exploration Costs............. 53,918 9,096 1,367 - 18,595 82,976 Development Costs............. 247,705 28,045 41,262 - - 317,012 --------- ------- -------- ------- ------- -------- Total............... $ 331,934 $44,295 $ 42,629 $ - $19,482 $438,340 ========= ======= ======== ======= ======= ======== </TABLE> F-27
60 Results of Operations for Oil and Gas Producing Activities(1). The following tables set forth results of operations for oil and gas producing activities for the years ended December 31: <TABLE> <CAPTION> FOREIGN --------------------------------------------- UNITED STATES CANADA TRINIDAD INDIA OTHER TOTAL ------------- ------- -------- ------- -------- -------- <S> <C> <C> <C> <C> <C> <C> 1995 Operating Revenues Associated Companies..................... $ 223,652 $ 6,893 $ - $ - $ - $230,545 Trade.................................... 122,567 36,815 71,686 15,411 - 246,479 Gains on Sales of Reserves and Related Assets......................... 62,737 84 - - - 62,821 --------- ------- ------- ------- -------- -------- Total.............................. 408,956 43,792 71,686 15,411 - 539,845 Exploration Expenses, including Dry Hole... 35,298 3,839 374 (98) 15,542 54,955 Production Costs........................... 63,734 13,825 8,176 10,553 - 96,288 Impairment of Unproved Oil and Gas Properties............................... 21,981 1,734 - - - 23,715 Depreciation, Depletion and Amortization............................. 180,788 19,533 14,633 335 368 215,657 --------- ------- ------- ------- -------- -------- Income (Loss) before Income Taxes.......... 107,155 4,861 48,503 4,621 (15,910) 149,230 Income Tax Provision (Benefit)............. 1,226 1,133 26,677 2,311 (1,335) 30,012 --------- ------- ------- ------- -------- -------- Results of Operations...................... $ 105,929 $ 3,728 $21,826 $ 2,310 $(14,575) $119,218 ========= ======= ======= ======= ======== ======== 1994 Operating Revenues Associated Companies..................... $ 315,866 $ 8,452 $ - $ - $ - $324,318 Trade.................................... 115,375 42,017 35,908 509 - 193,809 Gains on Sales of Reserves and Related Assets......................... 54,026 (12) - - - 54,014 --------- ------- ------- ------- -------- -------- Total.............................. 485,267 50,457 35,908 509 - 572,141 Exploration Expenses, including Dry Hole... 42,242 4,503 836 2,302 9,125 59,008 Production Costs........................... 68,998 12,776 5,083 26 - 86,883 Impairment of Unproved Oil and Gas Properties............................... 23,862 1,074 - - - 24,936 Depreciation, Depletion and Amortization............................. 218,433 16,572 6,572 - 281 241,858 --------- ------- ------- ------- -------- -------- Income (Loss) before Income Taxes.......... 131,732 15,532 23,417 (1,819) (9,406) 159,456 Income Tax Provision (Benefit)............. (8,617) 6,175 12,804 (910) (2,873) 6,579 --------- ------- ------- ------- -------- -------- Results of Operations...................... $ 140,349 $ 9,357 $10,613 $ (909) $ (6,533) $152,877 ========= ======= ======= ======= ======== ======== 1993 Operating Revenues Associated Companies..................... $ 369,824 $ 9,637 $ - $ - $ - $379,461 Trade.................................... 140,552 33,228 1,209 - - 174,989 Gains on Sales of Reserves and Related Assets......................... 13,724 (406) - - - 13,318 --------- ------- ------- ------- -------- -------- Total.............................. 524,100 42,459 1,209 - - 567,768 Exploration Expenses, including Dry Hole... 35,029 6,657 1,367 - 12,223 55,276 Production Costs........................... 75,767 14,063 1,496 - - 91,326 Impairment of Unproved Oil and Gas Properties............................... 19,499 968 - - - 20,467 Depreciation, Depletion and Amortization............................. 234,292 14,630 387 - 154 249,463 --------- ------- ------- ------- -------- -------- Income (Loss) before Income Taxes.......... 159,513 6,141 (2,041) - (12,377) 151,236 Income Tax Provision (Benefit)............. (15,525) 2,265 (1,020) - (1,742) (16,022) --------- ------- ------- ------- -------- -------- Results of Operations...................... $ 175,038 $ 3,876 $(1,021) $ - $(10,635) $167,258 ========= ======= ======= ======= ======== ======== </TABLE> - --------------- (1) Excludes net revenues associated with other marketing activities, interest charges, general corporate expenses and certain gathering and handling fees for each of the three years in the period ended December 31, 1995. The gathering and handling fees and other marketing net revenues are directly associated with oil and gas operations with regard to segment reporting as defined in SFAS No. 14 - "Financial Reporting for Segments of a Business Enterprise", but are not part of Disclosures about Oil and Gas Producing Activities as defined in SFAS No. 69. F-28
61 Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves. The following information has been developed utilizing procedures prescribed by SFAS No. 69 and based on crude oil and natural gas reserve and production volumes estimated by the engineering staff of the Company. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company. The future cash flows presented below are based on sales prices, cost rates, and statutory income tax rates in existence as of the date of the projections. It is expected that material revisions to some estimates of crude oil and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used. Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated. The presentation of the standardized measure of discounted future net cash flows and changes therein has been restated to exclude, for each of the years presented, amounts attributable to future deliveries required under a volumetric production payment at the equivalent wellhead value. In order to calculate such amounts, the Company has assumed that deliveries under the volumetric production payment are made as scheduled and that production costs corresponding to the volumes delivered are incurred by the Company at average rates for the properties subject to the production payment. This restatement was made following discussions with the Staff of the Securities and Exchange Commission. The Company has also presented, as additional information, the standardized measure of discounted future net cash flows and changes therein including amounts attributable to future deliveries required under the volumetric production payment. The Company believes that this information is informative to readers of its financial statements because the related oil and gas properties costs and deferred revenue are shown in the Company's balance sheets for each of the years presented. This additional information is not required to be presented in accordance with SFAS No. 69; however, the Company believes this additional information is useful in assessing its reserve and financial position on a comprehensive basis. F-29
62 The following table sets forth the standardized measure of discounted future net cash flows from projected production of the Company's crude oil and natural gas reserves at December 31, for the years ended December 31: <TABLE> <CAPTION> UNITED STATES CANADA TRINIDAD INDIA TOTAL ----------- --------- --------- --------- ----------- <S> <C> <C> <C> <C> <C> 1995 Future cash inflows(1)............................... $ 3,996,029 $ 502,803 $ 395,328 $ 396,130 $ 5,290,290 Future production costs.............................. (747,064) (203,906) (152,287) (202,410) (1,305,667) Future development costs............................. (297,859) (7,153) (3,610) (13,500) (322,122) ----------- --------- --------- --------- ----------- Future net cash flows before income taxes............ 2,951,106 291,744 239,431 180,220 3,662,501 Future income taxes.................................. (695,843) (46,310) (105,188) (81,349) (928,690) ----------- --------- --------- --------- ----------- Future net cash flows................................ 2,255,263 245,434 134,243 98,871 2,733,811 Discount to present value at 10% annual rate......... (1,015,123) (68,861) (19,217) (45,470) (1,148,671) ----------- --------- --------- --------- ----------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves...... 1,240,140 176,573 115,026 53,401 1,585,140 Additional disclosures: Amounts attributable to volumetric production payment.......................................... 35,957 - - - 35,957 ----------- --------- --------- --------- ----------- Total discounted future net revenues, including amounts attributable to volumetric production payment.......................................... $ 1,276,097 $ 176,573 $ 115,026 $ 53,401 $ 1,621,097 =========== ========= ========= ========= =========== 1994 Future cash inflows(1)............................... $ 2,315,215 $ 487,050 $ 317,758 $ 168,370 $ 3,288,393 Future production costs.............................. (606,932) (196,275) (87,479) (105,840) (996,526) Future development costs............................. (135,768) (9,596) (1,781) (4,500) (151,645) ----------- --------- --------- --------- ----------- Future net cash flows before income taxes............ 1,572,515 281,179 228,498 58,030 2,140,222 Future income taxes.................................. (208,163) (57,220) (102,171) (22,482) (390,036) ----------- --------- --------- --------- ----------- Future net cash flows................................ 1,364,352 223,959 126,327 35,548 1,750,186 Discount to present value at 10% annual rate......... (401,547) (67,018) (22,897) (14,730) (506,192) ----------- --------- --------- --------- ----------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves...... 962,805 156,941 103,430 20,818 1,243,994 Additional disclosures: Amounts attributable to volumetric production payment.......................................... 60,269 - - - 60,269 ----------- --------- --------- --------- ----------- Total discounted future net revenues, including amounts attributable to volumetric production payment.......................................... $ 1,023,074 $ 156,941 $ 103,430 $ 20,818 $ 1,304,263 =========== ========= ========= ========= =========== 1993 Future cash inflows(1)............................... $ 3,154,790 $ 592,845 $ 147,542 $ - $ 3,895,177 Future production costs.............................. (639,760) (230,230) (45,385) - (915,375) Future development costs............................. (165,473) (21,001) (7,582) - (194,056) ----------- --------- --------- --------- ----------- Future net cash flows before income taxes............ 2,349,557 341,614 94,575 - 2,785,746 Future income taxes.................................. (487,017) (91,718) (35,477) - (614,212) ----------- --------- --------- --------- ----------- Future net cash flows................................ 1,862,540 249,896 59,098 - 2,171,534 Discount to present value at 10% annual rate......... (600,172) (90,125) (9,519) - (699,816) ----------- --------- --------- --------- ----------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves...... 1,262,368 159,771 49,579 - 1,471,718 Additional disclosures: Amounts attributable to volumetric production payment.......................................... 105,323 - - - 105,323 ----------- --------- --------- --------- ----------- Total discounted future net revenues, including amounts attributable to volumetric production payment.......................................... $ 1,367,691 $ 159,771 $ 49,579 $ - $ 1,577,041 =========== ========= ========= ========= =========== </TABLE> - --------------- (1) Based on year end market prices determined at the point of delivery from the producing unit. F-30
63 Changes in Standardized Measure of Discounted Future Net Cash Flows. The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, for each of the three years in the period ended December 31, 1995. <TABLE> <CAPTION> UNITED STATES CANADA TRINIDAD INDIA TOTAL ----------- -------- -------- -------- ---------- <S> <C> <C> <C> <C> <C> Standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 1992.................................................... $ 1,183,692 $125,419 $ - $ - $1,309,111 Additional disclosures: Amounts attributable to volumetric production payment... 127,724 - - - 127,724 ----------- -------- -------- -------- ---------- Total discounted future net revenues relating to proved oil and gas reserves, including amounts attributable to volumetric production payment, at December 31, 1992.................................................. $ 1,311,416 $125,419 $ - $ - $1,436,835 =========== ======== ======== ======== ========== Standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 1992.................................................... $ 1,183,692 $125,419 $ - $ - $1,309,111 Sales and transfers of oil and gas produced, net of production costs...................................... (388,251) (28,802) 287 - (416,766) Net changes in prices and production costs.............. 158,102 28,400 - - 186,502 Extensions, discoveries, additions and improved recovery net of related costs.................................. 275,722 27,785 74,191 - 377,698 Development costs incurred.............................. 58,500 13,900 - - 72,400 Revisions of estimated development costs................ 32,196 (1,345) - - 30,851 Revisions of previous quantity estimates................ (26,118) 5,668 - - (20,450) Accretion of discount................................... 128,461 15,348 - - 143,809 Net change in income taxes.............................. (76,755) (9,795) (24,899) - (111,449) Purchases of reserves in place.......................... 9,462 2,707 - - 12,169 Sales of reserves in place.............................. (36,919) (1,140) - - (38,059) Changes in timing and other............................. (55,724) (18,374) - - (74,098) ----------- -------- -------- -------- ---------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 1993.................................................... 1,262,368 159,771 49,579 - 1,471,718 Additional disclosures: Amounts attributable to volumetric production payment... 105,323 - - - 105,323 ----------- -------- -------- -------- ---------- Total discounted future net revenues relating to proved oil and gas reserves, including amounts attributable to volumetric production payment, at December 31, 1993.................................................. $ 1,367,691 $159,771 $ 49,579 $ - $1,577,041 =========== ======== ======== ======== ========== Standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 1993.................................................... $ 1,262,368 $159,771 $ 49,579 $ - $1,471,718 Sales and transfers of oil and gas produced, net of production costs...................................... (339,809) (37,693) (30,825) (483) (408,810) Net changes in prices and production costs.............. (506,273) (65,287) 11,002 - (560,558) Extensions, discoveries, additions and improved recovery net of related costs.................................. 225,366 51,006 96,515 - 372,887 Development costs incurred.............................. 69,900 6,700 7,582 - 84,182 Revisions of estimated development costs................ 6,792 5,931 - - 12,723 Revisions of previous quantity estimates................ (2,909) (3,407) 14,077 - 7,761 Accretion of discount................................... 145,119 19,762 7,448 - 172,329 Net change in income taxes.............................. 167,983 19,966 (45,789) (7,752) 134,408 Purchases of reserves in place.......................... 16,651 3,404 - 29,053 49,108 Sales of reserves in place.............................. (27,980) (461) - - (28,441) Changes in timing and other............................. (54,403) (2,751) (6,159) - (63,313) ----------- -------- -------- -------- ---------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 1994.................................................... 962,805 156,941 103,430 20,818 1,243,994 Additional disclosures: Amounts attributable to volumetric production payments.............................................. 60,269 - - - 60,269 ----------- -------- -------- -------- ---------- Total discounted future net revenues relating to proved oil and gas reserves, including amounts attributable to volumetric production payment, at December 31, 1994.................................................. $ 1,023,074 $156,941 $103,430 $ 20,818 $1,304,263 =========== ======== ======== ======== ========== </TABLE> (Table continued on following page) F-31
64 <TABLE> <CAPTION> UNITED STATES CANADA TRINIDAD INDIA TOTAL ---------- -------- -------- ----- ---------- <S> <C> <C> <C> <C> <C> Standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 1994.................................................... $ 962,805 $156,941 $103,430 $ 20,818 $1,243,994 Sales and transfers of oil and gas produced, net of production costs...................................... (268,463) (29,883) (63,510) (4,858) (366,714) Net changes in prices and production costs.............. 12,079 (5,698) (37,035) 7,857 (22,797) Extensions, discoveries, additions and improved recovery net of related costs.................................. 376,474(1) 38,028 53,674 46,180 514,356 Development costs incurred.............................. 29,100 2,600 1,800 - 33,500 Revisions of estimated development costs................ 920 139 28,771 4,500 34,330 Revisions of previous quantity estimates................ 5,694 (5,217) 10,142 (29) 10,590 Accretion of discount................................... 97,248 17,483 17,412 2,857 135,000 Net change in income taxes.............................. (132,614) 10,592 (8,048) (28,127) (158,197) Purchases of reserves in place.......................... 193,711 - - - 193,711 Sales of reserves in place.............................. (54,441) (569) - - (55,010) Changes in timing and other............................. 17,627 (7,843) 8,390 4,203 22,377 ----------- -------- -------- -------- ---------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 1995.................................................... 1,240,140 176,573 115,026 53,401 1,585,140 Additional disclosures: Amounts attributable to volumetric production payment... 35,957 - - - 35,957 ----------- -------- -------- -------- ---------- Total discounted future net revenues relating to proved oil and gas reserves, including amounts attributable to volumetric production payment, at December 31, 1995.................................................. $ 1,276,097 $176,573 $115,026 $ 53,401 $1,621,097 =========== ======== ======== ======== ========== </TABLE> - --------------- (1) Includes approximately $77 million related to the reserves in the Big Piney deep Paleozoic formations. F-32
65 UNAUDITED QUARTERLY FINANCIAL INFORMATION <TABLE> <CAPTION> QUARTER ENDED ----------------------------------------------- MARCH 31 JUNE 30 SEPT. 30 DEC. 31 -------- -------- -------- -------- <S> <C> <C> <C> <C> 1995 Net Operating Revenues................... $155,362 $183,974 $153,006 $156,360 ======== ======== ======== ======== Operating Income......................... $ 42,829 $ 73,374 $ 37,925 $ 41,181 ======== ======== ======== ======== Income before Income Taxes............... $ 39,500 $ 71,331 $ 33,344 $ 39,879 Income Tax Provision..................... 9,875 23,193 376 8,492 -------- -------- -------- -------- Net Income............................... $ 29,625 $ 48,138 $ 32,968 $ 31,387 ======== ======== ======== ======== Earnings per Share of Common Stock....... $ .19 $ .30 $ .21 $ .20 ======== ======== ======== ======== Average Number of Common Shares.......... 159,972 159,965 159,916 159,817 ======== ======== ======== ======== 1994 Net Operating Revenues................... $158,208 $155,449 $160,683 $151,483 ======== ======== ======== ======== Operating Income......................... $ 38,938 $ 39,081 $ 52,020 $ 29,602 ======== ======== ======== ======== Income before Income Taxes............... $ 39,088 $ 36,581 $ 50,497 $ 27,769 Income Tax Provision (Benefit)........... 8,830 2,369 9,529 (14,791) -------- -------- -------- -------- Net Income............................... $ 30,258 $ 34,212 $ 40,968 $ 42,560 ======== ======== ======== ======== Earnings per Share of Common Stock....... $ .19 $ .21 $ .26 $ .27 ======== ======== ======== ======== Average Number of Common Shares.......... 159,840 159,859 159,777 159,902 ======== ======== ======== ======== 1993 Net Operating Revenues................... $136,834 $140,486 $152,647 $151,053 ======== ======== ======== ======== Operating Income......................... $ 29,633 $ 31,517 $ 38,451 $ 15,958 ======== ======== ======== ======== Income before Income Taxes............... $ 28,955 $ 29,598 $ 37,168 $ 16,552 Income Tax Provision (Benefit)........... (1,253) (3,923) 1,412 (21,988) -------- -------- -------- -------- Net Income............................... $ 30,208 $ 33,521 $ 35,756 $ 38,540 ======== ======== ======== ======== Earnings per Share of Common Stock....... $ .19 $ .21 $ .22 $ .24 ======== ======== ======== ======== Average Number of Common Shares.......... 160,000 160,000 160,000 159,865 ======== ======== ======== ======== </TABLE> F-33
66 SCHEDULE II ENRON OIL & GAS COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993 (IN THOUSANDS) <TABLE> <CAPTION> ========================================================================================================== COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E - ---------------------------------------------------------------------------------------------------------- ADDITIONS DEDUCTIONS FOR BALANCE AT CHARGED TO PURPOSE FOR BALANCE AT BEGINNING OF COSTS AND WHICH RESERVES END OF DESCRIPTION YEAR EXPENSES WERE CREATED YEAR <S> <C> <C> <C> <C> - ---------------------------------------------------------------------------------------------------------- 1995 Reserves deducted from assets to which they apply - Revaluation of Accounts Receivable....... $1,022 $1,549 $ - $2,571 ====== ====== ====== ====== Litigation Reserve(a)...................... $2,000 $ (379)(b) $1,621 $ - ====== ====== ====== ====== 1994 Reserves deducted from assets to which they apply - Revaluation of Accounts Receivable....... $1,020 $ 2 $ - $1,022 ====== ====== ====== ====== Litigation Reserve(a)...................... $2,000 $3,143 $3,143 $2,000 ====== ====== ====== ====== 1993 Reserves deducted from assets to which they apply - Revaluation of Accounts Receivable....... $ - $1,020 $ - $1,020 ====== ====== ====== ====== Litigation Reserve(a)...................... $2,030 $2,520 $2,550 $2,000 ====== ====== ====== ====== </TABLE> - --------------- (a) Included in Other Liabilities in the consolidated balance sheets. (b) Includes reversal of prior year provision in excess of requirement. S-1
67 EXHIBITS Exhibits not incorporated herein by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated herein by reference to the Company's Form S-1 Registration Statement, Registration No. 33-30678, filed on August 24, 1989 ("Form S-1"), or as otherwise indicated. <TABLE> <S> <C> 3.1(a) - Restated Certificate of Incorporation of Enron Oil & Gas Company (Exhibit 3.1 to Form S-1). 3.1(b) - Certificate of Amendment of Restated Certificate of Incorporation of Enron Oil & Gas Company (Exhibit 4.1(b) to Form S-8 Registration Statement, Registration No. 33-52201, filed on February 8, 1994). 3.1(c) - Certificate of Amendment of Restated Certificate of Incorporation of Enron Oil & Gas Company (Exhibit 4.1(c) to Form S-8 Registration Statement, Registration No. 33-58103, filed on March 15, 1995). 3.2* - By-laws of Enron Oil & Gas Company dated August 23, 1989, as amended December 12, 1990, February 8, 1994 and January 19, 1996. 3.3 - Specimen of Certificate evidencing the Common Stock (Exhibit 3.3 to Form S-1). 4.1 - Promissory Note due May 1, 1996, dated May 1, 1991 (Exhibit 4.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 1991). 4.3 - Amended and Restated Enron Oil & Gas Company 1994 Stock Plan (Exhibit 4.3 to Form S-8 Registration Statement, Registration No. 33-58103, filed on March 15, 1995). 4.3(a)* - Amendment to Amended and Restated Enron Oil & Gas Company 1994 Stock Plan, dated effective as of December 12, 1995. 10.1 - Services Agreement, dated as of January 1, 1994, between Enron Oil & Gas Company and Enron Corp. (Exhibit 10.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.2 - Stock Restriction and Registration Agreement dated as of August 23, 1989 (Exhibit 10.2 to Form S-1). 10.3* - 1995 Tax Allocation Agreement, entered into effective as of December 14, 1995, between Enron Corp., Enron Oil & Gas Company, and the subsidiaries of Enron Oil & Gas Company listed therein as additional parties. 10.4 - Enron Corp. Deferral Plan dated December 10, 1985 (Exhibit 10.12 to Form S-1). 10.5 - Enron Corp. 1988 Stock Plan (Exhibit 10.13 to Form S-1). 10.7 - Enron Corp. 1984 Stock Option Plan (Exhibit 10.15 to Form S-1). 10.8 - Enron Corp. 1986 Stock Option Plan (Exhibit 10.16 to Form S-1). 10.9(a) - Employment Agreement between Enron Oil & Gas Company and Forrest Hoglund, dated as of September 1, 1987, as amended (Exhibit 10.19 to Form S-1), and Second and Third Amendments to Employment Agreement dated June 30, 1989 and February 14, 1992, respectively (Exhibit 10.10 to Form S-1 Registration Statement, Registration No. 33-50462, filed on August 5, 1992). 10.9(b) - 4th Amendment to Employment Agreement dated December 14, 1994, among Enron Corp., Enron Oil & Gas Company and Forrest Hoglund (Exhibit 10.9(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.10 - Fuel Supply Contract, dated as of June 30, 1986, by and between Enron Oil & Gas Company, HNG Oil Company, BelNorth Petroleum Corporation and Enron Cogeneration One Company, as amended (Exhibit 10.23 to Form S-1). </TABLE> E-1
68 <TABLE> <S> <C> 10.11 - Gas Sales Contract dated September 2, 1987 between Enron Oil & Gas Company and Cogenron Inc., as amended (Exhibit 10.24 to Form S-1). 10.12 - Letter Agreement dated August 20, 1987 between Enron Oil & Gas Company and Panhandle Gas Company (Exhibit 10.25 to Form S-1). 10.13 - Pension Program for Enron Corp. Deferral Plan Participants, effective January 1, 1985, as amended (Exhibit 10.29 to Form S-1). 10.14 - Enron Oil & Gas Company 1993 Non-employee Director Stock Option Plan (Exhibit 10.14 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992). 10.15(a) - Credit Agreement, dated as of March 11, 1994, among Enron Oil & Gas Company, the Banks named therein and Texas Commerce Bank, National Association, as Administrative Agent and Promissory Note due January 15, 1998, dated March 11, 1994 to the order of Texas Commerce Bank National Association, Promissory Note due January 15, 1998, dated March 11, 1994 to the order of The Bank of New York, Promissory Note due January 15, 1998, dated March 11, 1994 to the order of The Bank of Nova Scotia, Promissory Note due January 15, 1998, dated March 11, 1994 to the order of Credit Lyonnais Cayman Islands Branch, Promissory Note due January 15, 1998, dated March 11, 1994 to the order of Credit Suisse, Promissory Note due January 15, 1998, dated March 11, 1994 to the order of The First National Bank of Chicago, and Promissory Note due January 15, 1998, dated March 11, 1994 to the order of Bank of America National Trust and Savings Association (Exhibit 10.15 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.15(b) - Assignment and Acceptance dated April 14, 1994, between Texas Commerce Bank National Association and Royal Bank of Canada and Promissory Note due January 15, 1998, dated April 14, 1994, to the order of Texas Commerce Bank National Association and Promissory Note due January 15, 1998, dated April 14, 1994, to the order of Royal Bank of Canada (Exhibit 10.15(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.16 - Interest Rate and Currency Exchange Agreement, dated as of June 1, 1991, between Enron Risk Management Services Corp. and Enron Oil & Gas Marketing, Inc. (Exhibit 10.17 to the Company's Annual Report on Form 10-K for the year ended December 31, 1991), Confirmation dated June 14, 1992 (Exhibit 10.17 to Form S-1 Registration Statement, Registration No. 33-50462, filed on August 5, 1992) and Confirmations dated March 25, 1991, April 25, 1991, and September 23, 1992 (assigned to Enron Risk Management Services Corp. by Enron Finance Corp. pursuant to an Assignment and Assumption Agreement, dated as of November 1, 1993, by and between Enron Finance Corp., Enron Risk Management Services Corp. and Enron Oil & Gas Marketing, Inc.). (Exhibit 10.16 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.17 - Assignment and Assumption Agreement, dated as of November 1, 1993, by and between Enron Oil & Gas Marketing, Inc., Enron Oil & Gas Company and Enron Risk Management Services Corp. (Exhibit 10.17 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.18 - ISDA Master Agreement, dated as of November 1, 1993, between Enron Oil & Gas Company and Enron Risk Management Services Corp., and Confirmation Nos. 1268.0, 1286.0, 1291.0, 1292.0, 1304.0, 1305.0, 1321.0, 1335.0, 1338.0, 1370.0, 1471.0, 1485.0, 1486.0, 1494.0, 1495.0, 1509.0, 1514.0, 1533.01, 1569.0, 1986.0, 2217.0, 2227.0, 2278.0, 2299.0, 2372.0, 2647.0 (Exhibit 10.18 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). </TABLE> E-2
69 <TABLE> <S> <C> 10.19 - Letter Agreement between Colorado Interstate Gas Company and Enron Oil & Gas Marketing, Inc. dated November 1, 1990 (Exhibit 10.18 to the Company's Annual Report on Form 10-K for the year ended December 31, 1990). 10.22 - Gas Sales Agreement between Enron Gas Marketing, Inc. and Enron Oil & Gas Marketing, Inc. dated August 22, 1989 (Exhibit 10.38 to Form S-1). 10.23 - Gas Purchase Agreement between Enron Oil & Gas Company and Enron Oil & Gas Marketing, Inc. dated August 22, 1989 (Exhibit 10.41 to Form S-1). 10.24 - Gas Purchase Agreement between Enron Oil & Gas Company and Enron Oil & Gas Marketing, Inc. dated August 22, 1989 (Exhibit 10.42 to Form S-1). 10.25 - Enron Corp. 1991 Stock Plan (Exhibit 10.08 to Enron Corp. Annual Report on Form 10-K for the year ended December 31, 1991). 10.26 - Enron Corp. 1988 Deferral Plan (Exhibit 10.49 to Form S-1). 10.27 - Form of Enron Corp. Long-Term Incentive Plan Effective as of January 1, 1987 (Exhibit 10.50 to Form S-1). 10.28 - Enron Executive Supplemental Survivor Benefits Plan Effective January 1, 1987 (Exhibit 10.51 to Form S-1). 10.29 - 1988 FlexPerq Program Summary (Exhibit 10.52 to Form S-1). 10.30* - Credit Agreement between Enron Corp. and Enron Oil & Gas Company dated September 29, 1995. 10.31* - Credit Agreement between Enron Oil & Gas Company and Enron Corp. dated September 29, 1995. 10.33 - Swap Agreement between Banque Paribas and Enron Oil & Gas Company, dated as of December 5, 1990 (Exhibit 10.37 to the Company's Annual Report on Form 10-K for the year ended December 31, 1990), and Confirmations dated March 25, 1991 and April 25, 1991 (Exhibit 10.37 to Form S-1 Registration Statement, Registration No. 33-50462, filed on August 5, 1992). 10.34 - Enron Oil & Gas Company 1992 Stock Plan (As Amended and Restated effective December 14, 1994) (incorporated by reference to Exhibit A to the Company's Proxy Statement, dated March 27, 1995, with respect to the Company's 1995 Annual Meeting of Shareholders). 10.35 - Enron Corp. 1992 Deferral Plan (Exhibit 10.41 to the Company's Annual Report on Form 10-K for the year ended December 31, 1991). 10.36(a) - Conveyance of Production Payment, dated September 25, 1992, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.34 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992). 10.36(b) - First Amendment to Conveyance of Production Payment, dated effective April 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.36(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.36(c) - Second Amendment to Conveyance of Production Payment, dated effective July 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.36(c) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.36(d) - Third Amendment to Conveyance of Production Payment, dated effective October 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.36(d) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). </TABLE> E-3
70 <TABLE> <S> <C> 10.37(a) - Hydrocarbon Exchange Agreement dated September 25, 1992, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.35 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992). 10.37(b) - Amendment to Hydrocarbon Exchange Agreement dated effective as of January 1, 1993, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.37(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.37(c) - First Amendment to Hydrocarbon Exchange Agreement dated effective as of April 1, 1993, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.37(c) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.37(d) - Second Amendment to Hydrocarbon Exchange Agreement dated effective as of July 1, 1993, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.37(d) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.37(e) - Amendment to Hydrocarbon Exchange Agreement dated effective as of August 1, 1993, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.37(e) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.37(f) - Fourth Amendment to Hydrocarbon Exchange Agreement, dated effective October 1, 1993, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.37 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.38 - Purchase and Sale Agreement, dated September 25, 1992, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.36 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992). 10.39(a) - Production and Delivery Agreement, dated September 25, 1992, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.37 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992). 10.39(b) - First Amendment to Production and Delivery Agreement, dated effective April 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.39(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.39(c) - Second Amendment to Production and Delivery Agreement, dated effective July 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.39(c) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.39(d) - Third Amendment to Production and Delivery Agreement, dated effective October 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.39(d) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.40 - Credit Agreement, dated as of March 8, 1994 between Enron Gas & Oil Trinidad Limited and Caribbean Regional Development Investment Trust, and Request for Advance No. 1, dated March 4, 1993, and Request for Advance No. 2, dated March 4, 1993 (Exhibit 10.40 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). </TABLE> E-4
71 <TABLE> <S> <C> 10.41 - Promissory Note due May 1, 1998, dated as of March 8, 1994, to the order of Caribbean Regional Development Investment Trust (Exhibit 10.41 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.42 - Promissory Note due May 1, 1998, dated as of March 8, 1994 to the order of Caribbean Regional Development Investment Trust (Exhibit 10.42 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.43 - Letter of Credit and Reimbursement Agreement, dated March 8, 1994, between Enron Gas & Oil Trinidad Limited and Credit Suisse (Exhibit 10.43 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.44 - Parent Guaranty, dated March 8, 1994 between Enron Oil & Gas Company and Credit Suisse (Exhibit 10.44 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.45(a) - Letter Loan Agreement dated as of May 27, 1994, between Enron Gas & Oil Trinidad Limited and The Bank of Nova Scotia (Exhibit 10.45(a) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.45(b) - Promissory Note due May 27, 1999, dated as of May 31, 1994, to the order of The Bank of Nova Scotia (Exhibit 10.45(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.45(c) - Promissory Note due May 27, 1999, dated as of January 10, 1995, to the order of The Bank of Nova Scotia (Exhibit 10.45(c) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.46 - Guaranty dated as of May 27, 1994, between Enron Oil & Gas Company and The Bank of Nova Scotia (Exhibit 10.46 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.47 - Attorney Opinion Letter of Enron Oil & Gas International, Inc. dated December 18, 1994 (Panna and Mukta Fields) (Exhibit 10.47 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.48 - Certificate of Enron Oil & Gas India Ltd. dated December 22, 1994 (Panna and Mukta Fields) (Exhibit 10.48 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.49 - Financial and Performance Guarantee of Enron Oil & Gas International, Inc. dated December 22, 1994 (Panna and Mukta Fields) (Exhibit 10.49 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.50 - Joint Operating Agreement effective as of December 22, 1994, among Oil & Natural Gas Corporation Limited, Enron Oil & Gas India Ltd. and Reliance Industries Limited for contract area identified as Panna and Mukta Fields (Appendices B-1 and B-2 have been intentionally omitted. The Company hereby agrees to furnish a copy of either appendix to the Commission upon request) (Exhibit 10.50 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.51 - Production Sharing Contract dated as of December 22, 1994, among The Government of India, Oil & Natural Gas Corporation Limited, Reliance Industries Limited and Enron Oil & Gas India Ltd., for contract area identified as Panna and Mukta Fields [Appendices B-1 and B-2 and Appendix G (Figures G-1, VIIA-1 to 10, VIIB-1 to 20 and VIII-3) have all been intentionally omitted. The Company hereby agrees to furnish a copy of any such appendix and/or figure to the Commission upon request] (Exhibit 10.51 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). </TABLE> E-5
72 <TABLE> <S> <C> 10.52 - Attorney Opinion Letter of Enron Oil & Gas International, Inc. dated December 18, 1994 (Tapti Fields) (Exhibit 10.52 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.53 - Certificate of Enron Oil & Gas India Ltd. dated December 22, 1994 (Tapti Fields) (Exhibit 10.53 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.54 - Financial and Performance Guarantee of Enron Oil & Gas International, Inc. dated December 22, 1994 (Tapti Fields) (Exhibit 10.54 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.55 - Joint Operating Agreement effective as of December 22, 1994, among Oil & Natural Gas Corporation Limited, Enron Oil & Gas India Ltd. and Reliance Industries Limited, for contract area identified as Mid-Tapti and South-Tapti Gas Fields [Appendix B (Figure B-1) has been intentionally omitted. The Company hereby agrees to furnish a copy of such appendix to the Commission upon request] (Exhibit 10.55 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.56 - Production Sharing Contract dated as of December 22, 1994, among The Government of India, Oil & Natural Gas Corporation Limited, Reliance Industries Limited and Enron Oil & Gas India Ltd., for contract area identified as Mid and South Tapti Field [Appendix B, Appendix G (Figures G-1, VII-1 to 11, VIII-2 to 4 and Appendix 3) have all been intentionally omitted. The Company hereby agrees to furnish a copy of any such appendix, to the Commission upon request] (Exhibit 10.56 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.57(a)* - Letter Agreement relating to Natural Gas Swap Transactions, dated March 31, 1995, among Enron Oil & Gas Company, Enron Corp. and Enron Capital & Trade Resources Corp. 10.57(b)* - Amendment to Natural Gas Swap Transactions Letter Agreement, dated March 31, 1995, among Enron Oil & Gas Company, Enron Corp. and Enron Capital & Trade Resources Corp. 10.58* - Confirmation Letter (revised due to adjustments to the attached Payment Schedule), dated March 31, 1995, between Enron Oil & Gas Company and Enron Capital & Trade Resources Corp. (ECT Transaction Reference No. 15198.00). 10.59* - Confirmation Letter (revised due to Price Change for 1998 and adjustment to the attached Payment Schedule), dated March 31, 1995, between Enron Oil & Gas Company and Enron Capital & Trade Resources Corp. (ECT Transaction Reference No. 15198.01). 10.60* - Letter Agreement relating to swap transaction payments, dated February 1995, between Enron Oil & Gas Company and Enron Capital & Trade Resources Corp. 10.64* - Credit Agreement, dated as of January 16, 1996, among EOG Company of Canada, as the Borrower, and the Banks named therein and Texas Commerce Bank National Association, as Administrative Agent, and Promissory Note due January 17, 2001, dated January 16, 1996, to the order of Texas Commerce Bank National Association, Promissory Note due January 17, 2001, dated January 16, 1996, to the order of Commerzbank Aktiengesellschaft, Promissory Note due January 17, 2001, dated January 16, 1996, to the order of Royal Bank of Canada, Promissory Note due January 17, 2001, dated January 16, 1996, to the order of The Bank of New York, and Promissory Note due January 17, 2001, dated January 16, 1996, to the order of The Bank of Nova Scotia. </TABLE> E-6
73 <TABLE> <S> <C> 10.65* - Guaranty, dated as of January 16, 1996, by Enron Oil & Gas Company, as Guarantor, in favor of the Banks named therein and Texas Commerce Bank National Association, as Administrative Agent. 10.66* - ISDA Master Agreement, dated as of January 16, 1996, between Royal Bank of Canada and EOG Company of Canada. 10.67* - ISDA Master Agreement, dated as of January 16, 1996, between Royal Bank of Canada and Enron Oil & Gas Company. 10.68* - Guaranty, dated effective as of January 16, 1996, by Enron Oil & Gas Company in favor of Royal Bank of Canada. 21* - List of subsidiaries. 23.1* - Consent of DeGolyer and MacNaughton. 23.2* - Opinion of DeGolyer and MacNaughton dated January 22, 1996. 23.3* - Consent of Arthur Andersen LLP. 24* - Powers of Attorney. 27* - Financial Data Schedule. </TABLE> E-7
74 SIGNATURES Pursuant to the requirements of section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 5th day of March, 1996. ENRON OIL & GAS COMPANY (Registrant) By /s/ WALTER C. WILSON --------------------------------- (Walter C. Wilson) Senior Vice President and Chief Financial Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of registrant and in the capacities with Enron Oil & Gas Company indicated and on the 5th day of March, 1996. SIGNATURE TITLE --------- ----- /s/ FORREST E. HOGLUND Chairman of the Board, President and Chief - ------------------------------- Executive Officer and Director (Principal (Forrest E. Hoglund) Executive Officer) /s/ WALTER C. WILSON Senior Vice President and Chief Financial - ------------------------------- Officer (Principal Financial Officer) (Walter C. Wilson) /s/ BEN B. BOYD Vice President and Controller (Principal - ------------------------------- Accounting Officer) (Ben B. Boyd) FRED C. ACKMAN* Director - ------------------------------- (Fred C. Ackman) RICHARD D. KINDER* Director - ------------------------------- (Richard D. Kinder) KENNETH L. LAY* Director - ------------------------------- (Kenneth L. Lay) EDWARD RANDALL, III* Director - ------------------------------- (Edward Randall, III) *By /s/ ANGUS H. DAVIS ---------------------------- (Angus H. Davis) (Attorney-in-fact for persons indicated)
75 INDEX TO EXHIBITS <TABLE> <S> <C> 3.1(a) - Restated Certificate of Incorporation of Enron Oil & Gas Company (Exhibit 3.1 to Form S-1). 3.1(b) - Certificate of Amendment of Restated Certificate of Incorporation of Enron Oil & Gas Company (Exhibit 4.1(b) to Form S-8 Registration Statement, Registration No. 3352201, filed on February 8, 1994). 3.1(c) - Certificate of Amendment of Restated Certificate of Incorporation of Enron Oil & Gas Company (Exhibit 4.1(c) to Form S-8 Registration Statement, Registration No. 3358103, filed on March 15, 1995). 3.2* - By-laws of Enron Oil & Gas Company dated August 23, 1989, as amended December 12, 1990, February 8, 1994 and January 19, 1996. 3.3 - Specimen of Certificate evidencing the Common Stock (Exhibit 3.3 to Form S-1). 4.1 - Promissory Note due May 1, 1996, dated May 1, 1991 (Exhibit 4.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 1991). 4.3 - Amended and Restated Enron Oil & Gas Company 1994 Stock Plan (Exhibit 4.3 to Form S-8 Registration Statement, Registration No. 3358103, filed on March 15, 1995). 4.3(a)* - Amendment to Amended and Restated Enron Oil & Gas Company 1994 Stock Plan, dated effective as of December 12, 1995. 10.1 - Services Agreement, dated as of January 1, 1994, between Enron Oil & Gas Company and Enron Corp. (Exhibit 10.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.2 - Stock Restriction and Registration Agreement dated as of August 23, 1989 (Exhibit 10.2 to Form S-1). 10.3* - 1995 Tax Allocation Agreement, entered into effective as of December 14, 1995, between Enron Corp., Enron Oil & Gas Company, and the subsidiaries of Enron Oil & Gas Company listed therein as additional parties. 10.4 - Enron Corp. Deferral Plan dated December 10, 1985 (Exhibit 10.12 to Form S-1). 10.5 - Enron Corp. 1988 Stock Plan (Exhibit 10.13 to Form S-1). 10.7 - Enron Corp. 1984 Stock Option Plan (Exhibit 10.15 to Form S-1). 10.8 - Enron Corp. 1986 Stock Option Plan (Exhibit 10.16 to Form S-1). 10.9(a) - Employment Agreement between Enron Oil & Gas Company and Forrest Hoglund, dated as of September 1, 1987, as amended (Exhibit 10.19 to Form S-1), and Second and Third Amendments to Employment Agreement dated June 30, 1989 and February 14, 1992, respectively (Exhibit 10.10 to Form S-1 Registration Statement, Registration No. 3350462, filed on August 5, 1992). 10.9(b) - 4th Amendment to Employment Agreement dated December 14, 1994, among Enron Corp., Enron Oil & Gas Company and Forrest Hoglund (Exhibit 10.9(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.10 - Fuel Supply Contract, dated as of June 30, 1986, by and between Enron Oil & Gas Company, HNG Oil Company, BelNorth Petroleum Corporation and Enron Cogeneration One Company, as amended (Exhibit 10.23 to Form S-1). </TABLE>
76 <TABLE> <S> <C> 10.11 - Gas Sales Contract dated September 2, 1987 between Enron Oil & Gas Company and Cogenron Inc., as amended (Exhibit 10.24 to Form S-1). 10.12 - Letter Agreement dated August 20, 1987 between Enron Oil & Gas Company and Panhandle Gas Company (Exhibit 10.25 to Form S-1). 10.13 - Pension Program for Enron Corp. Deferral Plan Participants, effective January 1, 1985, as amended (Exhibit 10.29 to Form S-1). 10.14 - Enron Oil & Gas Company 1993 Non-employee Director Stock Option Plan (Exhibit 10.14 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992). 10.15(a) - Credit Agreement, dated as of March 11, 1994, among Enron Oil & Gas Company, the Banks named therein and Texas Commerce Bank, National Association, as Administrative Agent and Promissory Note due January 15, 1998, dated March 11, 1994 to the order of Texas Commerce Bank National Association, Promissory Note due January 15, 1998, dated March 11, 1994 to the order of The Bank of New York, Promissory Note due January 15, 1998, dated March 11, 1994 to the order of The Bank of Nova Scotia, Promissory Note due January 15, 1998, dated March 11, 1994 to the order of Credit Lyonnais Cayman Islands Branch, Promissory Note due January 15, 1998, dated March 11, 1994 to the order of Credit Suisse, Promissory Note due January 15, 1998, dated March 11, 1994 to the order of The First National Bank of Chicago, and Promissory Note due January 15, 1998, dated March 11, 1994 to the order of Bank of America National Trust and Savings Association (Exhibit 10.15 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.15(b) - Assignment and Acceptance dated April 14, 1994, between Texas Commerce Bank National Association and Royal Bank of Canada and Promissory Note due January 15, 1998, dated April 14, 1994, to the order of Texas Commerce Bank National Association and Promissory Note due January 15, 1998, dated April 14, 1994, to the order of Royal Bank of Canada (Exhibit 10.15(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.16 - Interest Rate and Currency Exchange Agreement, dated as of June 1, 1991, between Enron Risk Management Services Corp. and Enron Oil & Gas Marketing, Inc. (Exhibit 10.17 to the Company's Annual Report on Form 10-K for the year ended December 31, 1991), Confirmation dated June 14, 1992 (Exhibit 10.17 to Form S-1 Registration Statement, Registration No. 3350462, filed on August 5, 1992) and Confirmations dated March 25, 1991, April 25, 1991, and September 23, 1992 (assigned to Enron Risk Management Services Corp. by Enron Finance Corp. pursuant to an Assignment and Assumption Agreement, dated as of November 1, 1993, by and between Enron Finance Corp., Enron Risk Management Services Corp. and Enron Oil & Gas Marketing, Inc.). (Exhibit 10.16 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.17 - Assignment and Assumption Agreement, dated as of November 1, 1993, by and between Enron Oil & Gas Marketing, Inc., Enron Oil & Gas Company and Enron Risk Management Services Corp. (Exhibit 10.17 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.18 - ISDA Master Agreement, dated as of November 1, 1993, between Enron Oil & Gas Company and Enron Risk Management Services Corp., and Confirmation Nos. 1268.0, 1286.0, 1291.0, 1292.0, 1304.0, 1305.0, 1321.0, 1335.0, 1338.0, 1370.0, 1471.0, 1485.0, 1486.0, 1494.0, 1495.0, 1509.0, 1514.0, 1533.01, 1569.0, 1986.0, 2217.0, 2227.0, 2278.0, 2299.0, 2372.0, 2647.0 (Exhibit 10.18 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). </TABLE>
77 <TABLE> <S> <C> 10.19 - Letter Agreement between Colorado Interstate Gas Company and Enron Oil & Gas Marketing, Inc. dated November 1, 1990 (Exhibit 10.18 to the Company's Annual Report on Form 10-K for the year ended December 31, 1990). 10.22 - Gas Sales Agreement between Enron Gas Marketing, Inc. and Enron Oil & Gas Marketing, Inc. dated August 22, 1989 (Exhibit 10.38 to Form S-1). 10.23 - Gas Purchase Agreement between Enron Oil & Gas Company and Enron Oil & Gas Marketing, Inc. dated August 22, 1989 (Exhibit 10.41 to Form S-1). 10.24 - Gas Purchase Agreement between Enron Oil & Gas Company and Enron Oil & Gas Marketing, Inc. dated August 22, 1989 (Exhibit 10.42 to Form S-1). 10.25 - Enron Corp. 1991 Stock Plan (Exhibit 10.08 to Enron Corp. Annual Report on Form 10-K for the year ended December 31, 1991). 10.26 - Enron Corp. 1988 Deferral Plan (Exhibit 10.49 to Form S-1). 10.27 - Form of Enron Corp. Long-Term Incentive Plan Effective as of January 1, 1987 (Exhibit 10.50 to Form S-1). 10.28 - Enron Executive Supplemental Survivor Benefits Plan Effective January 1, 1987 (Exhibit 10.51 to Form S-1). 10.29 - 1988 FlexPerq Program Summary (Exhibit 10.52 to Form S-1). 10.30* - Credit Agreement between Enron Corp. and Enron Oil & Gas Company dated September 29, 1995. 10.31* - Credit Agreement between Enron Oil & Gas Company and Enron Corp. dated September 29, 1995. 10.33 - Swap Agreement between Banque Paribas and Enron Oil & Gas Company, dated as of December 5, 1990 (Exhibit 10.37 to the Company's Annual Report on Form 10-K for the year ended December 31, 1990), and Confirmations dated March 25, 1991 and April 25, 1991 (Exhibit 10.37 to Form S-1 Registration Statement, Registration No. 3350462, filed on August 5, 1992). 10.34 - Enron Oil & Gas Company 1992 Stock Plan (As Amended and Restated effective December 14, 1994) (incorporated by reference to Exhibit A to the Company's Proxy Statement, dated March 27, 1995, with respect to the Company's 1995 Annual Meeting of Shareholders). 10.35 - Enron Corp. 1992 Deferral Plan (Exhibit 10.41 to the Company's Annual Report on Form 10-K for the year ended December 31, 1991). 10.36(a) - Conveyance of Production Payment, dated September 25, 1992, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.34 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992). 10.36(b) - First Amendment to Conveyance of Production Payment, dated effective April 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.36(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.36(c) - Second Amendment to Conveyance of Production Payment, dated effective July 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.36(c) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.36(d) - Third Amendment to Conveyance of Production Payment, dated effective October 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.36(d) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). </TABLE>
78 <TABLE> <S> <C> 10.37(a) - Hydrocarbon Exchange Agreement dated September 25, 1992, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.35 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992). 10.37(b) - Amendment to Hydrocarbon Exchange Agreement dated effective as of January 1, 1993, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.37(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.37(c) - First Amendment to Hydrocarbon Exchange Agreement dated effective as of April 1, 1993, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.37(c) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.37(d) - Second Amendment to Hydrocarbon Exchange Agreement dated effective as of July 1, 1993, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.37(d) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.37(e) - Amendment to Hydrocarbon Exchange Agreement dated effective as of August 1, 1993, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.37(e) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.37(f) - Fourth Amendment to Hydrocarbon Exchange Agreement, dated effective October 1, 1993, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.37 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.38 - Purchase and Sale Agreement, dated September 25, 1992, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.36 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992). 10.39(a) - Production and Delivery Agreement, dated September 25, 1992, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.37 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992). 10.39(b) - First Amendment to Production and Delivery Agreement, dated effective April 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.39(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.39(c) - Second Amendment to Production and Delivery Agreement, dated effective July 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.39(c) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.39(d) - Third Amendment to Production and Delivery Agreement, dated effective October 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.39(d) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.40 - Credit Agreement, dated as of March 8, 1994 between Enron Gas & Oil Trinidad Limited and Caribbean Regional Development Investment Trust, and Request for Advance No. 1, dated March 4, 1993, and Request for Advance No. 2, dated March 4, 1993 (Exhibit 10.40 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). </TABLE>
79 <TABLE> <S> <C> 10.41 - Promissory Note due May 1, 1998, dated as of March 8, 1994, to the order of Caribbean Regional Development Investment Trust (Exhibit 10.41 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.42 - Promissory Note due May 1, 1998, dated as of March 8, 1994 to the order of Caribbean Regional Development Investment Trust (Exhibit 10.42 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.43 - Letter of Credit and Reimbursement Agreement, dated March 8, 1994, between Enron Gas & Oil Trinidad Limited and Credit Suisse (Exhibit 10.43 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.44 - Parent Guaranty, dated March 8, 1994 between Enron Oil & Gas Company and Credit Suisse (Exhibit 10.44 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.45(a) - Letter Loan Agreement dated as of May 27, 1994, between Enron Gas & Oil Trinidad Limited and The Bank of Nova Scotia (Exhibit 10.45(a) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.45(b) - Promissory Note due May 27, 1999, dated as of May 31, 1994, to the order of The Bank of Nova Scotia (Exhibit 10.45(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.45(c) - Promissory Note due May 27, 1999, dated as of January 10, 1995, to the order of The Bank of Nova Scotia (Exhibit 10.45(c) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.46 - Guaranty dated as of May 27, 1994, between Enron Oil & Gas Company and The Bank of Nova Scotia (Exhibit 10.46 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.47 - Attorney Opinion Letter of Enron Oil & Gas International, Inc. dated December 18, 1994 (Panna and Mukta Fields) (Exhibit 10.47 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.48 - Certificate of Enron Oil & Gas India Ltd. dated December 22, 1994 (Panna and Mukta Fields) (Exhibit 10.48 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.49 - Financial and Performance Guarantee of Enron Oil & Gas International, Inc. dated December 22, 1994 (Panna and Mukta Fields) (Exhibit 10.49 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.50 - Joint Operating Agreement effective as of December 22, 1994, among Oil & Natural Gas Corporation Limited, Enron Oil & Gas India Ltd. and Reliance Industries Limited for contract area identified as Panna and Mukta Fields (Appendices B-1 and B-2 have been intentionally omitted. The Company hereby agrees to furnish a copy of either appendix to the Commission upon request) (Exhibit 10.50 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.51 - Production Sharing Contract dated as of December 22, 1994, among The Government of India, Oil & Natural Gas Corporation Limited, Reliance Industries Limited and Enron Oil & Gas India Ltd., for contract area identified as Panna and Mukta Fields [Appendices B-1 and B-2 and Appendix G (Figures G-1, VIIA-1 to 10, VIIB-1 to 20 and VIII-3) have all been intentionally omitted. The Company hereby agrees to furnish a copy of any such appendix and/or figure to the Commission upon request] (Exhibit 10.51 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). </TABLE>
80 <TABLE> <S> <C> 10.52 - Attorney Opinion Letter of Enron Oil & Gas International, Inc. dated December 18, 1994 (Tapti Fields) (Exhibit 10.52 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.53 - Certificate of Enron Oil & Gas India Ltd. dated December 22, 1994 (Tapti Fields) (Exhibit 10.53 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.54 - Financial and Performance Guarantee of Enron Oil & Gas International, Inc. dated December 22, 1994 (Tapti Fields) (Exhibit 10.54 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.55 - Joint Operating Agreement effective as of December 22, 1994, among Oil & Natural Gas Corporation Limited, Enron Oil & Gas India Ltd. and Reliance Industries Limited, for contract area identified as Mid-Tapti and South-Tapti Gas Fields [Appendix B (Figure B-1) has been intentionally omitted. The Company hereby agrees to furnish a copy of such appendix to the Commission upon request] (Exhibit 10.55 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.56 - Production Sharing Contract dated as of December 22, 1994, among The Government of India, Oil & Natural Gas Corporation Limited, Reliance Industries Limited and Enron Oil & Gas India Ltd., for contract area identified as Mid and South Tapti Field [Appendix B, Appendix G (Figures G-1, VII-1 to 11, VIII-2 to 4 and Appendix 3) have all been intentionally omitted. The Company hereby agrees to furnish a copy of any such appendix, to the Commission upon request] (Exhibit 10.56 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.57(a)* - Letter Agreement relating to Natural Gas Swap Transactions, dated March 31, 1995, among Enron Oil & Gas Company, Enron Corp. and Enron Capital & Trade Resources Corp. 10.57(b)* - Amendment to Natural Gas Swap Transactions Letter Agreement, dated March 31, 1995, among Enron Oil & Gas Company, Enron Corp. and Enron Capital & Trade Resources Corp. 10.58* - Confirmation Letter (revised due to adjustments to the attached Payment Schedule), dated March 31, 1995, between Enron Oil & Gas Company and Enron Capital & Trade Resources Corp. (ECT Transaction Reference No. 15198.00). 10.59* - Confirmation Letter (revised due to Price Change for 1998 and adjustment to the attached Payment Schedule), dated March 31, 1995, between Enron Oil & Gas Company and Enron Capital & Trade Resources Corp. (ECT Transaction Reference No. 15198.01). 10.60* - Letter Agreement relating to swap transaction payments, dated February 1995, between Enron Oil & Gas Company and Enron Capital & Trade Resources Corp. 10.64* - Credit Agreement, dated as of January 16, 1996, among EOG Company of Canada, as the Borrower, and the Banks named therein and Texas Commerce Bank National Association, as Administrative Agent, and Promissory Note due January 17, 2001, dated January 16, 1996, to the order of Texas Commerce Bank National Association, Promissory Note due January 17, 2001, dated January 16, 1996, to the order of Commerzbank Aktiengesellschaft, Promissory Note due January 17, 2001, dated January 16, 1996, to the order of Royal Bank of Canada, Promissory Note due January 17, 2001, dated January 16, 1996, to the order of The Bank of New York, and Promissory Note due January 17, 2001, dated January 16, 1996, to the order of The Bank of Nova Scotia. </TABLE>
81 <TABLE> <S> <C> 10.65* - Guaranty, dated as of January 16, 1996, by Enron Oil & Gas Company, as Guarantor, in favor of the Banks named therein and Texas Commerce Bank National Association, as Administrative Agent. 10.66* - ISDA Master Agreement, dated as of January 16, 1996, between Royal Bank of Canada and EOG Company of Canada. 10.67* - ISDA Master Agreement, dated as of January 16, 1996, between Royal Bank of Canada and Enron Oil & Gas Company. 10.68* - Guaranty, dated effective as of January 16, 1996, by Enron Oil & Gas Company in favor of Royal Bank of Canada. 21* - List of subsidiaries. 23.1* - Consent of DeGolyer and MacNaughton. 23.2* - Opinion of DeGolyer and MacNaughton dated January 22, 1996. 23.3* - Consent of Arthur Andersen LLP. 24* - Powers of Attorney. 27* - Financial Data Schedule. </TABLE>